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Dec 14, 2012 ... Advice Letters 2825-E, 2825-E-A, and 2825-E-B are effective as of May 23, 2013, per ..... Advice Letter (AL) #: 2825-E ...... CASIO Charges.
STATE OF CALIFORNIA

Edmund G. Brown Jr. Governor

PUBLIC UTILITIES COMMISSION SAN FRANCISCO, CA 94102-3298

May 30, 2013 Advice Letters: 2825-E 2825-E-A 2825-E-B

Akbar Jazayeri Vice President, Regulatory Operations Southern California Edison Company P O Box 800 Rosemead, CA 91770

SUBJECT: Submission of Transition Agreements Between SCE and Sycamore Cogeneration Company and Kern River Cogeneration Company Dear Mr. Jazayeri: Advice Letters 2825-E, 2825-E-A, and 2825-E-B are effective as of May 23, 2013, per Resolution E-4571.

Sincerely,

Edward F. Randolph, Director Energy Division

ADVICE LETTER (AL) SUSPENSION NOTICE ENERGY DIVISION

Utility Name: Southern California Edison Utility No./Type: U 338-E Advice Letter Nos. 2825-E & 2825-E-A Date AL filed: December 14, 2012 Utility Contact Person: Darrah Morgan Utility Phone No. (626) 302-2086

Date Utility Notified: December 26, 2012 via: e-mail [ x ] E-Mail to: [email protected] Fax No.: (626) 302-4829 ED Staff Contact: Noel Crisostomo For Internal Purposes Only:

Date Calendar Clerk Notified: _____/_____/_______ Date Commissioners/Advisors Notified: ___/___/___ [X] INITIAL SUSPENSION (up to 120 DAYS) This is to notify that the above-indicated AL is suspended for up to 120 days beginning January 13, 2012 for the following reason(s) below. If the AL requires a Commission resolution and the Commission’s deliberation on the resolution prepared by Energy Division extends beyond the expiration of the initial suspension period, the advice letter will be automatically suspended for up to 180 days beyond the initial suspension period. [ ] Section 455 Hearing is Required. A Commission resolution may be required to address the advice letter. [ ] Advice Letter Requests a Commission Order. [X] Advice Letter Requires Staff Review Expected duration of initial suspension period: 120 days. [ ] FURTHER SUSPENSION (up to 180 DAYS beyond initial suspension period) The AL requires a Commission resolution and the Commission’s deliberation on the resolution prepared by Energy Division has extended beyond the expiration of the initial suspension period. The advice letter is suspended for up to 180 days beyond the initial suspension period.

_____________________________________________ If you have any questions regarding this matter, please contact Noel Crisostomo at 415.703.5404 or via e-mail at [email protected]. cc: Akbar Jazayeri, SCE Leslie Starck c/o Karyn Gansecki, SCE Amber Wyatt, SCE Katie Sloan, SCE Andrew Schwartz, Energy Division Maria Salinas, ED Tariff Unit

Protestants to the advice letter: none

Akbar Jazayeri Vice President of Regulatory Operations

December 14, 2012 ADVICE 2825-E (U 338-E) PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA ENERGY DIVISION SUBJECT:

Submission of Transition Agreements Between SCE and Sycamore Cogeneration Company and Kern River Cogeneration Company

PURPOSE The purpose of this advice letter is to seek approval of two Transition Agreements, one between SCE and Sycamore Cogeneration Company (“Sycamore Transition Agreement”), and one between SCE and Kern River Cogeneration Company (“KRCC Transition Agreement”), entered into pursuant to the terms of Section 3 of the Combined Heat and Power (“CHP”) Program Settlement Agreement (“Settlement Agreement” or “Settlement”) and CHP Settlement Agreement Term Sheet (“Term Sheet”).1 Each Transition Agreement is comprised of (1) a Transition Power Purchase Agreement (“Transition PPA”), pursuant to which Sycamore and KRCC will each supply capacity and energy from certain generating units operating in baseload mode; and (2) the “Dispatchable Agreements” consisting of the Resource Adequacy (“RA”) Confirmation (“RA Confirm”), pursuant to which Sycamore and KRCC will each provide RA capacity from dispatchable units to SCE, and a Unit Contingent Toll Confirmation (“Toll Confirm”) pursuant to which Sycamore and KRCC will each provide dispatchable capacity, energy, and other products. Both the RA Confirm and the Toll Confirm are subject to an Edison Electric Institute (“EEI”) Master Power Purchase and Sale Agreement (“EEI Master”), and to Paragraph 10 to the Collateral Annex, including applicable annexes and appendices (collectively the “Dispatchable Agreements”). Copies of the Transition Agreements are attached hereto as Appendix A.

1

Any capitalized terms used in this Advice Letter but not defined herein have the meaning set forth in the Settlement Agreement and/or Term Sheet.

P.O. Box 800

8631 Rush Street

Rosemead, California 91770

(626) 302-3630

Fax (626) 302-4829

ADVICE 2825-E (U 338-E)

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December 14, 2012

BACKGROUND In 2008, diverse parties with divergent interests, including the three investor-owned utilities (“IOUs”), representatives of Qualifying Facilities (“QFs”), customer advocacy groups, and California Public Utilities Commission (“CPUC” or “Commission”) representatives, engaged in settlement negotiations. The purpose of the Settlement was to develop a state CHP program, create a smooth transition from the existing QF CHP program to a state-administered CHP program, and settle all CHP/QF litigation issues, such as retroactive payment issues.2 After a year and a half-long intensive negotiation process, the participating parties filed a joint motion for CPUC approval of the QF and CHP Settlement Agreement,Term Sheet, and attached Exhibits. Rule 12.1(d) of the CPUC’s Rules of Practice and Procedure provides that “[t]he Commission will not approve settlements, whether contested or uncontested, unless the settlement is reasonable in light of the whole record, consistent with law, and the public interest.” To assess reasonableness, the CPUC considers, among other things, whether the settlement negotiations were at arms-length and whether the parties were adequately represented.3 Accordingly, the CPUC approved the Settlement Agreement only after (1) considering the Settlement Agreement as a whole, its individual elements, as well as the interests at stake, and (2) finding the Agreement to be reasonable and the product of protracted, arms-length negotiations between sophisticated and well-represented parties with divergent interests, all of whom were required to compromise on some things, and none of whom received everything they wanted.4 The CPUC additionally found that the Settlement Agreement furthered the state policy objectives embodied in California Public Utilities Code Section 372(a), Assembly Bill 32, and the Energy Action Plan II.5 As described above, the Settlement is designed to comprehensively resolve disputes arising out of existing QF contracts, especially with regard to energy and capacity pricing, and to transition the existing QF PURPA program into a new QF/CHP program. To those ends, Section 2 of the Term Sheet describes the three periods covered by the Agreement: the Transition Period, the Initial Program Period, and the Second Program Period. The Transition Period is designed to facilitate the transition from the existing QF program to the new QF/CHP program. Section 3 of the Term Sheet describes the eligibility requirements for QF CHP facilities to enter into a Transition Agreement. Specifically, a CHP facility selling power to an IOU under a Legacy PPA or an extension thereof is eligible to sign a Transition PPA. 2

3 4 5

See Term Sheet at 1.1.; Pursuant to Decision (D.) 08-07-048, SCE filed Application (A.) 08-11-001 to retroactively apply the Qualifying Facility (“QF”) pricing adopted in D.07-09-040 for calculating shortrun avoided costs (“SRAC”). Re Pacific Gas & Electric Co., 30 CPUC 2d 189, 222. D.10-12-035 at 28, 35; Conclusion of Law No. 21. Id. at 35, 38; Conclusion of Law No. 19.

ADVICE 2825-E (U 338-E)

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Pursuant to the Settlement, capacity prices in Transition PPAs must conform with the pricing established in D.07-09-040. Energy pricing will be SRAC as calculated by the formulas specified in Section 10 of the Term Sheet. The standard form Transition PPA for Existing Qualifying Cogeneration Facilities (“Standard Form”) is included as an exhibit to the Term Sheet. The QF Settlement also provided for the sale of “Additional Dispatchable Capacity beyond the Transition PPA Capacity Product.” Section 3.4.1.2 of the Settlement Term Sheet provides: In addition to these standard products, a Seller may elect to sell to Buyer under a Transition PPA Additional Dispatchable Capacity above the standard contract capacity set forth in the Transition PPA. Buyer must negotiate in good faith for 120 days to amend the Transition PPA to incorporate a competitive market price for Additional Dispatchable Capacity. If negotiations are unsuccessful, Buyer and Seller will mediate the terms of the amendment using the mediation procedures set forth in Section 10.02 of the Transition PPA. This option was viewed as being limited to a small subset of QF CHPs, each with unique operational constraints.6 On October 15, 2012, Sycamore and KRCC, both affiliates of SCE, executed respective Transition Agreements, including agreements for the provision of dispatchable capacity with SCE. THE TRANSITION AGREEMENTS As noted above, the Transition Agreements are comprised of the Transition PPA and the Dispatchable Agreements. SCE used the Standard Form adopted by the CPUC in the QF Settlement as the basis for the Transition PPA. Any eligible CHP QF (i.e., a QF CHP holding a Legacy PPA or an extension of a Legacy PPA) – whether an affiliate of SCE or not – seeking to sell to IOUs in the CAISO could obtain a Transition PPA by completing an application available on SCE’s public website.7 The terms of the Standard Form require the sale of a “standardized” “Power Product” which includes “(a) the Net Contract Capacity and (b) all electric energy produced by the Generating Facility, net of all Station Use and any and all of the Site Host Load” as well as “Related Products” which include RA benefits, “Green Attributes,” and “Capacity Attributes.” Both the price and non-price terms in the Standard Form also are standardized.

6 7

See id. at § 3.4.1.2. See www.sce.com/EnergyProcurement/renewables/chp/chp-settlement.htm.

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The starting point for the parties’ negotiations of the Dispatchable Agreements was a number of pro forma agreements that SCE has used previously in requests for offers (“RFOs”). Collectively, the terms of the Dispatchable Agreements require the sale of a “Product” which includes “Capacity, Energy, Ancillary Services, and any other product derived from or associated with each Generating Unit, including any Green Attributes associated with the Capacity, Energy and Ancillary Services” as well as the “Capacity Attributes of the Generating Unit” which include RA benefits. The product and non-price terms are standardized in the Dispatchable Agreements. The price for dispatchable capacity, which was a negotiated term, is discussed in more detail below.

THE TRANSITION AGREEMENTS ARE CONSISTENT WITH CPUC DECISIONS AND RULES GOVERNING AFFILIATE TRANSACTIONS The CPUC’s Affiliate Transaction Rules adopted in D.97-12-088, as amended in D.0612-0298 generally prohibit SCE from taking actions that constitute affiliate abuse by providing preferential treatment, unfair competitive advantage, or non-public proprietary utility information to SCE affiliates. With respect to power procurement, the CPUC’s rules focus on the requirement that power sale transactions between affiliated entities are free of affiliate abuse in the form of self or reciprocal-dealing; the regulated utility may not use its resources to provide an unfair competitive advantage to its unregulated affiliates. Specifically, the Affiliate Transaction Rules generally prohibit utilities from engaging in resource procurement from an affiliate without prior approval from the Commission.9 The rules further state that a utility may not represent that it will provide, or actually provide, any preferential treatment to its affiliate (including, but not limited to terms and conditions, pricing, or timing).10 Additionally, the Commission requires the use of an Independent Evaluator (“IE”) in resource solicitations where there are affiliates, IOU-built, or IOU-turnkey bidders.11 As noted above, with the few exceptions described below, the Transition Agreements utilize “pro forma” terms developed in the QF Settlment and in SCE’s RFOs. SCE is thus taking a two-fold approach to demonstrating that the Transition Agreements are not the product of preferential treatment or affiliate abuse. First, as to those terms that are identical to those in the Standard Form or in the dispatchable agreement pro formas, SCE would expect the Commission to find that there is no possibility of affiliate abuse in light of the origins of these documents. Second, as to the non-standardized terms of the Transition Agreements that have been negotiated, there is sufficient evidence to demonstrate that there has been no affiliate abuse.

8 9

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See D.06-12-029, Appendix A-3, Affiliate Transaction Rules Applicable to Large California Utilities. Id. at Rule III.B. The Commission contemplated procurement from SCE’s unregulated affiliates when it approved the QF Settlement. Indeed, the Settlement requires SCE to enter into a Transition PPA with any eligible QF who requests one. Id. at Rule III.A. See D.04-12-048 at 135-136.

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A. Pro Forma Terms The terms of the Standard Form were determined through a process that was free of the exercise of market power by SCE. The Standard Form was the result of a process that involved a year and half of negotiations among the California Cogeneration Council (“CCC”), the Cogeneration Association of California (“CAC”), the Energy Producers and Users Coalition (“EPUC”), the Independent Energy Producers Association (“IEP”), Pacific Gas and Electric Company, SCE, San Diego Gas & Electric Company, The Utility Reform Network (“TURN”), and Division of Ratepayer Advocates (“DRA”). That is, it was negotiated by trade associations representing CHP interests (including nonaffiliate CHPs), (CCC, CAC, and EPUC), a trade association that represents a variety of merchant generators (IEP), three different IOUs, and two entities representing consumer interests (DRA and TURN). The inclusion of two separate customer advocacy groups is notable – DRA and TURN had every interest in ensuring that the Standard Form Transition PPA contained prices and provisions that did not reflect affiliate preference. Indeed, when the Commission approved the Settlement, it found that the Settlement was the result of arms-length settlement negotiations and compromise among divergent interests, and that the Settlement resulted in a procurement process for QF and CHP resources that is competitive, flexible, and allows for sufficient regulatory oversight.12 With respect to the Dispatchable Agreements, SCE has used the pro formas of these agreements in SCE’s CHP RFO, and similar forms of agreement have also been used as part of SCE’s All-Source RFOs. Any eligible CHP QF could participate in SCE’s CHP RFO and utilize these documents, or utilize these documents as a basis for bilateral discussions with SCE outside the RFO process. These documents have been used in SCE’s All-Source RFOs for the past several years. Specifically, with respect to the RA Confirm and Toll Confirm, SCE used the confirm terms, with some modifications that it previously employed, in its 2011 All-Source RFO. B. Negotiated Modifications Consistent with its treatment of all CHP QF counterparties, SCE was willing to consider, and make changes to, the Standard Form to accommodate the unique operational requirements of the counterparties’ generating units. SCE was willing to consider, and make changes to the pro forma Dispatchable Agreements if those changes added value. 1. Negotiated Modifications to the Standard Form Because Sycamore and KRCC are each comprised of two baseload and two dispatchable generating units, governed by different documents, the parties agreed to modify several sections in the Standard Form to create cohesive, integrated contracts

12

D.10-12-035, Findings of Fact 12, 16.

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for Sycamore and KRCC, respectively.13 Additionally, CPUC and FERC regulatory approval requirements were added in Article Two and Section 9.01(b) of both the Sycamore Transition PPA and the KRCC Transition PPA. As KRCC and Sycamore are affiliates of SCE, both CPUC and FERC prior approval is needed for the parties to operate under the agreements. 2. Negotiated Modifications to the pro forma Dispatchable Agreements The parties also negotiated substantive modifications to six standard terms of the pro forma Dispatchable Agreements.14 Two of these non-standard terms are in the RA Confirm, three are in the Toll Confirm, and one is in the EEI Master. In summary, those substantives changes are:

13 14 15



The parties agreed to add restrictions in the RA Confirm with respect to the seller’s right to replace RA from any one Unit by using another Unit under contract. As a consequence of the change to the standard term, it is within SCE’s sole discretion to approve seller’s replacement RA.



The parties agreed to update SCE’s then-existing standard form of the RA Confirm to incorporate recent changes to the CAISO Tariff relating to RA.15 The updates included (i) changing the definition of “Product” to capture flexibility, (ii) flattening the price shape, (iii) amending the settlement calculation to take the RA replacement rule into account, and (iv) adding language that specifies a reduction in payment in the event SCE replaces RA on the seller’s behalf.



The parties agreed that SCE assume some limited and a specific portion of the risk of GHG offset credit invalidation. SCE will have the GHG emission allowance invalidation risk if the following narrow conditions exist: 1) the invalidation occurred after SCE’s transfer of the GHG emission allowance to the seller, 2) offset credits were still in the possession of the seller or the entity authorized to implement the regulatory program, and 3) seller represents that it holds title to such invalidated offset credits. SCE has made this same modification for other non-affiliate parties.



SCE required the seller to post a full floating independent amount equal to 10% of the market value of the Transaction if the seller’s credit rating falls below a specified limit.

There are also some non-material modifications. All changes are reflected in the redline of the Standard Form, which is included as Appendix B to this Advice Letter. There are also a number of non-material modifications. All changes are reflected in the redline of the pro forma Dispatchable Agreements, included as Appendix B to this Advice Letter. Cal. Indep. Sys. Operator Corp., 141 FERC ¶ 61,135 (2012) (accepting tariff amendment implementing a Replacement Requirement for Resource Adequacy Maintenance Outages).

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The parties agreed to additions to the Toll Confirm requiring the seller to execute a Participating Generator Agreement, Meter Services Agreement (both defined in the CAISO Tariff), and any necessary grid interconnection agreements prior to start of the delivery period. In order to export power to the grid and sell into the CAISO market, the generator must execute these pro forma agreements with the CAISO. Additionally, these changes are consistent with similar provisions in the Standard Form and pro formas SCE uses in its renewable solicitations.



The parties conformed the dispute provisions in the EEI Master to match those in the Standard Form.

Additionally, similar to the modifications to the Standard Form, the parties included regulatory approvals and integrated the Dispatchable Agreements with Sycamore’s and KRCC’s respective Transition PPAs. 3. Negotiated Price for Dispatchable Capacity Unlike the price in the Standard Form, the QF Settlement did not establish a price for dispatchable capacity. As such, there was no standard price term for dispatchable capacity and the price for such capacity, therefore, had to be negotiated. SCE and KRCC/Sycamore negotiated the price for dispatchable capacity for more than nine months. The crux of the parties’ disagreement over price concerned the appropriate standard for determining the “competitive market price” for the dispatchable capacity product KRCC and Sycamore were offering. On the one hand, KRCC and Sycamore argued to the CPUC that the appropriate benchmark “market” was the price offered by Sycamore in the competitive CHP RFO.16 The price for this capacity in Sycamore’s RFO contract is $73/kW/yr.17 SCE, however, did not believe that the Sycamore RFO PPA best reflected the short-term competitive market prices,18 and SCE pointed to proprietary market sources for forecasts of capacity and energy in the CAISO market as the appropriate competitive market benchmark. In addition to these possible market benchmarks, the price paid for capacity under the CAISO’s Capacity Procurement Mechanism (“CPM”) is also relevant. Under the CPM, the CAISO procures “backstop” capacity from resources in danger of shutting down, on behalf of a load serving entity, to maintain grid reliability if there are insufficient system resources to serve local reliability constraints. Specifically, Section 43.2.6 of the CAISO Tariff states that the CAISO may issue a CPM designation for capacity at risk of

16 17 18

See KRCC/Sycamore letter to CPUC Energy Division dated September 27, 2012. See ER13-133. See SCE letter to CPUC Energy Division dated October 10, 2012.

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retirement. For resources in danger of shutting down, this backstop RA procurement can extend for up to 12 months. The current CPM price is $67.50/kW-year.19 Ultimately, after months of negotiation and engaging in a CPUC-monitored mediation pursuant to Section 3.4.1.2 of the QF Settlement Term Sheet, the parties agreed to a price of $51.96/kW-yr. The price in the Dispatchable Agreements is less than the current CPM and also less than the 2011 CPM price of $55/kW-year.20 Additionally, SCE’s customers will receive a financial benefit under the Transition Agreements compared to the Legacy PPA extensions under which Sycamore and KRCC are currently operating. If the parties do not receive the necessary regulatory approvals, and Sycamore and KRCC were allowed by the CPUC to continue operating under their Legacy PPA in the absence of a Transition Agreement,21 SCE’s customers would be paying significantly more for the capacity that would otherwise have been provided in the Dispatchable Agreements. The price differential between Sycamore’s Legacy PPA and the Sycamore Transition Agreement results in an estimated $5.0 million in benefits for SCE’s customers over the term of the Sycamore Transition Agreement. The price differential between KRCC’s Legacy PPA and the KRCC Transition Agreement results in an estimated $8.3 million in benefits for SCE’s customers over the term of the KRCC Transition Agreement. SCE will supplement this advice filing with a more precise cost comparison of the KRCC and Sycamore Transition Agreements with their Legacy PPAs within a week of this filing, as requested by Energy Division staff. Additionally, with respect to Sycamore, under its Legacy PPA, Sycamore only needed to operate at 80% of its contract capacity during the limited summer on-peak hours in order to qualify to receive its full capacity payment throughout the year. The Sycamore Transition Agreement has more stringent performance requirements, which provide additional system support benefits. Specifically, the Sycamore Transition Agreement requires that the facility operate at 95% of its firm capacity during each time-of-delivery period in order to receive full firm capacity payments under the Transition PPA, and that the facility remain 100% available to receive full capacity payments under the Dispatchable Agreements.

19 20 21

See CAISO Tariff, Section 43.7.1, available at http://www.caiso.com/Documents/TariffSections3643_Nov5_2012.pdf See CAISO Tariff, Section 43.6.1, available at http://www.caiso.com/Documents/Sections40-44FourthReplacementCAISOTariff.pdf SCE would argue that such an extension would be inappropriate under the terms of the QF Settlement. However, it is not clear what action the CPUC would take if the Transition Agreements were not approved by the Commission.

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C. An Independent Evaluator Oversaw All Negotiations and Communications with KRCC and Sycamore Consistent with the requirement in D.04-12-046, the negotiation process and the communications regarding the KRCC and Sycamore Transition Agreements were overseen and monitored by an IE. The IE for this transaction was Merrimack Energy Group, Inc. (“Merrimack”). SCE utilized Merrimack in this Transition effort as well as the CHP RFO to ensure consistency in implementing the CHP Settlement Agreement. The IE was retained for this effort prior to engaging KRCC and Sycamore on the Transition Agreements. The IE reviewed the Transition Agreements and monitored all communications and negotiations with KRCC and Sycamore. The IE report is included as Appendix C. The confidential portion of the IE report is attached hereto as Appendix D. CONFIDENTIALITY In accordance with D. 91-05-007, D. 06-06-066, D. 08-04-023, D. 11-07-028 and General Order (GO) 96-B, SCE requests confidential treatment of Appendix D to this advice letter. That appendix is the confidential portion of the IE report, and confidential treatment of that appendix is supported by the confidentiality declaration attached to this Advice Letter as Appendix E. The confidential material in this Advice Letter will be made available to appropriate parties in accordance with and upon execution of SCE’s Proposed Non-Disclosure Agreement. Parties wishing to obtain access to the confidential material of this Advice Letter may contact Amber Wyatt in SCE’s Law Department at [email protected] or (626) 302-6961 to obtain a non-disclosure agreement. The information in this Advice Letter for which SCE requests confidential treatment, and the length of time it should remain confidential, are provided in Appendix F. This information is entitled to confidentiality protection, as provided in the IOU Matrix, pursuant to D. 06-06-066. The specific provisions of the IOU Matrix that apply to the confidential information in this Advice Letter are identified in Appendix F. REQUEST FOR COMMISSION APPROVAL The terms of the Sycamore and KRCC Transition Agreements are conditioned on the occurrence of final “CPUC Approval,” as it is described in the Transition Agreements. In order to satisfy that condition with respect to the Transition Agreements, SCE requests that the Commission issue a final and non-appealable resolution containing: 1. Approval of the Transition Agreements in their entirety; and 2. Any other and further relief as the Commission finds just and reasonable. SCE asks the Commission to approve the Transition Agreements within 60 days so that deliveries under the Transition Agreements may begin.

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TIER DESIGNATION Pursuant to Section 4.10.2 of the Settlement, which provides that “IOUs will utilize a Tier 3 Advice Letter for all other PPAs (new, repowering, or existing PPAs that contain any material modification of the PPAs approved in this Settlement),” SCE submits this Advice Letter with a Tier 3 designation. EFFECTIVE DATE This Advice Letter will become effective upon CPUC approval. NOTICE Anyone wishing to protest this advice filing may do so by letter via U.S. Mail, facsimile, or electronically, any of which must be received no later than 20 days after the date of this advice filing. Protests should be mailed to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Avenue San Francisco, California 94102 E-mail: [email protected] CPUC, Energy Division Attn: Noel Crisostomo 505 Van Ness Avenue San Francisco, California 94102 E-mail: [email protected] In addition, protests and all other correspondence regarding this advice letter should also be sent by letter and transmitted via facsimile or electronically to the attention of: Akbar Jazayeri Vice President of Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California 91770 Facsimile: (626) 302-4829 E-mail: [email protected]

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Leslie E. Starck Senior Vice President c/o Karyn Gansecki 601 Van Ness Avenue, Suite 2030 San Francisco, California 94102 Facsimile: (415) 929-5540 E-mail: [email protected] With a copy to: Amber Dean Wyatt Senior Attorney 2244 Walnut Grove Avenue Rosemead, California 91770 Facsimile: (626) 302-6961 Email: [email protected] There are no restrictions on who may file a protest, but the protest shall set forth specifically the grounds upon which it is based and shall be submitted expeditiously. In accordance with Section 4 of GO 96-B, SCE is serving copies of this advice filing to the interested parties shown on the attached GO 96-B, R.12-03-014, and A.08-11-001 et al service lists. Address change requests to the GO 96-B service list should be directed by electronic mail to [email protected] or at (626) 302-4039. For changes to all other service lists, please contact the CPUC’s Process Office at (415) 703-2021 or by electronic mail at [email protected]. Further, in accordance with Public Utilities Code Section 491, notice to the public is hereby given by filing and keeping the advice filing at SCE’s corporate headquarters. To view other SCE advice letters filed with the CPUC, log on to SCE’s web site at http://www.sce.com/AboutSCE/Regulatory/adviceletters. For questions, please contact Katie Sloan at (626) 302-6842 or by electronic mail at [email protected]. Southern California Edison Company

Akbar Jazayeri AJ:ks:jm Enclosures

CALIFORNIA PUBLIC UTILITIES COMMISSION ADVICE LETTER FILING SUMMARY ENERGY UTILITY MUST BE COMPLETED BY UTILITY (Attach additional pages as needed)

Company name/CPUC Utility No.: Southern California Edison Company (U 338-E) Utility type:

Contact Person: Darrah Morgan

 ELC

 GAS

 PLC

 HEAT

Phone #: (626) 302-2086  WATER

E-mail: [email protected] E-mail Disposition Notice to: [email protected]

EXPLANATION OF UTILITY TYPE

ELC = Electric PLC = Pipeline

GAS = Gas HEAT = Heat

Advice Letter (AL) #: Subject of AL:

(Date Filed/ Received Stamp by CPUC)

WATER = Water

2825-E

Tier Designation:

3

Submission of Transition Agreements Between SCE and Sycamore Cogeneration Company and Kern River Cogeneration Company

Keywords (choose from CPUC listing):

Compliance, Procurement

AL filing type:  Monthly  Quarterly  Annual  One-Time  Other If AL filed in compliance with a Commission order, indicate relevant Decision/Resolution #:

Does AL replace a withdrawn or rejected AL? If so, identify the prior AL: Summarize differences between the AL and the prior withdrawn or rejected AL1: Confidential treatment requested?  Yes  No If yes, specification of confidential information: See Appendix E Confidential information will be made available to appropriate parties who execute a nondisclosure agreement. Name and contact information to request nondisclosure agreement/access to confidential information: Amber Wyatt, SCE Law Department, at (626) 302-6961 or [email protected] Resolution Required?  Yes  No Requested effective date:

Upon CPUC Approval

No. of tariff sheets:

-0-

Estimated system annual revenue effect: (%): Estimated system average rate effect (%): When rates are affected by AL, include attachment in AL showing average rate effects on customer classes (residential, small commercial, large C/I, agricultural, lighting). Tariff schedules affected: Service affected and changes proposed1: Pending advice letters that revise the same tariff sheets:

1

Discuss in AL if more space is needed.

None

Protests and all other correspondence regarding this AL are due no later than 20 days after the date of this filing, unless otherwise authorized by the Commission, and shall be sent to: CPUC, Energy Division Attention: Tariff Unit 505 Van Ness Ave., San Francisco, CA 94102 [email protected]

CPUC, Energy Division Attention: Noel Crisostomo 505 Van Ness Ave., San Francisco, CA 94102 [email protected]

Akbar Jazayeri Vice President of Regulatory Operations Southern California Edison Company 8631 Rush Street Rosemead, California 91770 Facsimile: (626) 302-4829 E-mail: [email protected] Leslie E. Starck Senior Vice President c/o Karyn Gansecki Southern California Edison Company 601 Van Ness Avenue, Suite 2030 San Francisco, California 94102 Facsimile: (415) 929-5540 E-mail: [email protected] With a copy to: Amber Dean Wyatt Senior Attorney 2244 Walnut Grove Avenue Rosemead, CA 91770 Facsimile: (626) 302-6961 E-mail: [email protected]

Appendix A

MASTER POWER PURCHASE AND SALE AGREEMENT COVER SHEET This Master Power Purchase and Sale Agreement (Version 2.1; modified 4/25/00) (“Master Agreement” or “Transition Master Agreement”) is made as of the following date: October 15, 2012 (“Effective Date”). The Transition Master Agreement, together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support, margin agreement, or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the “Agreement”. The Parties to this Transition Master Agreement are the following: Name: Kern River Cogeneration Company (“Party A”)

Name: Southern California Edison Company (“Party B”)

All Notices:

All Notices:

Street: P. O. Box 80598

Street: 2244 Walnut Grove Ave., G.O.1, Quad 1C

City: Bakersfield

Zip: 93380

City: Rosemead, CA

Zip: 91770

Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610 Duns: 17-357-0292 Federal Tax ID Number: 95-3880295

Attn: Contract Administration Phone: (626) 302-3126 Facsimile: (626) 302-8168 Duns: 006908818 Federal Tax ID Number: 95-1240335

Invoices: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Invoices: Attn: Power Procurement - Finance Phone: (626) 302-3277 Facsimile: (626) 302-3276 Email: [email protected]

Scheduling: Attn: Control Room Phone: 661-615-4639 Facsimile: 661-615-4623

Scheduling: Attn: Manager of Energy Operations Phone: (626) 302-5730 Facsimile: (626) 307-4413

Payments: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Payments: Attn: Accounts Receivable - Power Procurement Southern California Edison Company PO Box 800 Rosemead, CA 91770 Phone: (626) 302-9371 Facsimile: (626) 302-9392

Wire Transfer: BNK: JP Morgan Chase ABA: 021-0000-21 ACCT: 910-2588-697

Wire Transfer: BNK: JPMorgan Chase Bank ABA: 021000021 ACCT: 323-394434

Credit and Collections: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Credit and Collections: Attn: Manager of Credit Phone: (626) 302-3383 Facsimile: (626) 302-2517

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Confirmations: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

Confirmations: Attn: Confirmation Coordinator Phone: (626) 307-4485 Facsimile: (626) 302-3410

With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

With additional Notices of an Event of Default or Potential Event of Default to: Southern California Edison Company 2244 Walnut Grove Ave., G.O.1, Quad 1C Rosemead, CA 91770 Attn: Manager of Energy Contracts Phone: (626) 302-3312 Facsimile: (626) 302-8168

The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions: Party A Tariff

Tariff Original Volume No. 1

Party B Tariff

Tariff Original Vol. No. 8

Dated March 21, 2010 Dated 09/01/2002

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Docket Number ER10-611-000 Docket Number ER 02-2263-000

Article Two Transaction Terms and Conditions

Optional provision in Section 2.4. If not checked, inapplicable.

Article Four Remedies for Failure to Deliver or Receive

Accelerated Payment of Damages. If not checked, inapplicable.

Article Five Events of Default; Remedies

5.1(g) Cross Default for Party A: Party A: Kern River Cogeneration Company Other Entity:

Cross Default Amount $1,000,000

Cross Default Amount $_____NA___

5.1(g) Cross Default for Party B: Party B: Southern California Edison Company.

Cross Default Amount $75,000,000

Other Entity: Not Applicable.

Cross Default Amount

5.6 Closeout Setoff Option A, as amended. Option B - Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows: Option C (No Setoff). Article Eight Credit and Collateral Requirements

8.1 Party A Credit Protection: (a) Financial Information: Option A, as amended. Option B Specify: Option C Specify:

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(b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex.

(d) Downgrade Event: Not Applicable. Applicable. If applicable, complete the following: It shall be a Downgrade Event for Party B if Party B’s Credit Rating falls below ______ from S&P or _________ from Moody's or ______ from Fitch or if Party B is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party B: Not Applicable. Guarantee Amount: Not Applicable. 8.2 Party B Credit Protection: (a) Financial Information: Option A, as amended. Option B, as amended. Specify: [Guarantor or other party specified, if applicable]________________ Option C Specify: ___________ (b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex. (d) Downgrade Event: Not Applicable. Applicable.

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If applicable, complete the following: It shall be a Downgrade Event for Party A if Party A’s Credit Rating falls below ___ from S&P or ___ from Moody's or ______ from Fitch or if Party A is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party A: Guarantee Amount: $__________ Article Ten Confidentiality Schedule M

Confidentiality Applicable. If not checked, inapplicable. Party A is a Governmental Entity or Public Power System. Party B is a Governmental Entity or Public Power System. Add Section 3.6. If not checked, inapplicable. Add Section 8.4. If not checked, inapplicable.

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Other Changes

The following changes shall be applicable. ARTICLE ONE: GENERAL DEFINITIONS. Amend Article One as follows: Section 1.4 is amended by (i) deleting the word “or” in the first line, and (ii) inserting the words “, or the Friday immediately following the U.S. Thanksgiving holiday” immediately after “Bank holiday”. Section 1.11 is amended by (i) deleting the words “attorneys’ fees and” and (ii) inserting the words “(excluding attorneys’ fees)” after the word “expenses” in the fifth line. Section 1.12 is amended by replacing the word “issues” in the fourth line with the word “issuer”, and replacing the phrase “S&P, Moody’s or any other rating agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement” with the phrase “the Ratings Agencies”. Section 1.24 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.27 is amended to read as follows: “1.27 ‘Letter of Credit’ means an irrevocable, nontransferable standby letter of credit, issued by a major U.S. commercial bank or the U.S. branch office of a foreign bank with, in either case, a Credit Rating of at least (a) A- by S&P, A3 by Moody’s, and A- by Fitch, if such entity is rated by the Ratings Agencies; or (b) A- by S&P, A3 by Moody’s, or A- by Fitch, if such entity is rated by only one or two of the Ratings Agencies, in substantially the form attached hereto as Schedule 1, with such changes to the terms in that form as the issuing bank may require and as may be acceptable to the beneficiary thereof. Costs of a Letter of Credit shall be borne by the applicant for such Letter of Credit.” Section 1.28 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.29 is amended by inserting the words “or ‘Transition Master Agreement’ ” immediately after “Master Agreement”. Section 1.50 is amended by replacing the term “Section 2.4” with the term “Section 2.5”. Section 1.51 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, from an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Buyer’s option,” the phrase “absent a purchase from an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. Section 1.53 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, to an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Seller’s option,” the phrase “absent a sale to an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. New Sections 1.62, 1.63, 1.64, 1.65, 1.66, 1.67, 1.68, 1.69, 1.70, 1.71 and 1.72 are

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added to read as follows: “1.62 ‘CPUC Approval’ means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement and the Transition PPA in their respective entirety, including payments to be made by Party B, subject to CPUC review of Party B’s administration of each of the Agreement and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and nonappealable.” “1.63 ‘FERC Approval’ means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.7(a) of this Agreement in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal.” “1.64 ‘Fitch’ means Fitch Ratings Ltd. or its successor.” “1.65 ‘Forward Price Assessments’ means quotations solicited or obtained in good faith from regularly published and widely-distributed forward price assessments from a broker that is not an Affiliate of either Party and who is actively participating in markets for the relevant Products.” “1.66 ‘Market Quotation Average Price’ means the arithmetic mean of the quotations solicited in good faith from not less than three (3) Reference MarketMakers (as hereinafter defined); provided, however, that the Party obtaining the quotes shall use reasonable efforts to obtain good faith quotations from at least five (5) Reference Market-Makers and, if at least five (5) such quotations are obtained, the Market Quotation Average Price shall be determined by disregarding the highest and lowest quotations and taking the arithmetic mean of the remaining quotations. The quotations shall be based on the offers to sell or bids to buy, as applicable, obtained for transactions substantially similar to each Terminated Transaction. The quote must be obtained assuming that the Party obtaining the quote will provide sufficient credit support for the proposed transaction. Each quotation shall be obtained in good faith by such Party, to the extent reasonably practicable, as of the same day and time (without regard to different time zones) on or as soon as reasonably practicable after the relevant Early Termination Date, such day and time as of which those quotations will be selected shall be specified in accordance with Section 5.2. If fewer than three (3) quotations are obtained, it will be deemed that the Market Quotation Average Price in respect of such Terminated Transaction or group of Terminated Transactions cannot be determined.” “1.67 ‘Merger Event’ means, with respect to a Party or its Guarantor, that such

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Party or its Guarantor consolidates or amalgamates with, merges into or with, or transfers substantially all its assets to another entity and (i) the resulting entity fails to assume all the obligations of such Party hereunder or of such Party’s Guarantor under its guaranty, or (ii) the benefits of any credit support provided by such Party pursuant to Article Eight, or any guaranty provided by such Party’s Guarantor, fail to extend the performance by such resulting, surviving or transferee entity of its obligations hereunder, or (iii) the resulting entity’s creditworthiness is materially weaker than that of such Party or its Guarantor immediately prior to such action. The creditworthiness of the resulting entity shall not be deemed to be ‘materially weaker’ so long as the resulting entity maintains a Credit Rating of at least that of the applicable Party or its Guarantor, as the case may be, immediately prior to the consolidation, merger or transfer.” “1.68 ‘Ratings Agency’ means any of S&P, Moody’s, and Fitch, and any other ratings agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement (collectively the ‘Ratings Agencies’).” “1.69 ‘Reference Market-Maker’ means a leading dealer in the relevant market that is not an Affiliate of either Party and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker.” “1.70 ‘Specified Energy Transaction’ means the Transition PPA or any transaction (including an agreement with respect to any such transaction) now existing or hereafter entered into between Party A and Party B (or any Guarantor of such Party) which is not a Transaction under this Agreement, but which is a transaction under the International Swaps and Derivatives Association Master Agreement, the North American Energy Standards Board Base Contract for Purchase and Sale of Natural Gas, the WSPP Agreement, or under any other agreement with respect to the purchase, sale, or transfer of (a) wholesale physical electric energy or capacity; (b) wholesale physical natural gas; or (c) financial derivative products related thereto.” “1.71 ‘Transition Collateral Annex’ has the meaning set forth in Section 5.1(e).” “1.72 ‘Transition PPA’ means that certain Power Purchase and Sale Agreement, dated October 15, 2012, between Party A and Party B, as may be amended from time to time.”

ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS. Amend Article Two as follows: Section 2.1 is amended by adding the following sentence to the end thereof “Any Transaction formed and effectuated pursuant to the foregoing shall be considered a ‘writing’ or ‘in writing’ and to have been ‘signed’ by each Party or otherwise binding on the Parties.” Section 2.2 is amended to delete the second comma after the words “supplements hereto),” and before “the Party” in the second sentence. Section 2.4 is amended by (i) deleting the words “either orally or” after the phrase “Section 2.3 unless agreed to” in the second to last line thereof. Section 2.5 is amended (i) to delete the phrase “Unless a Party expressly objects to a

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Recording (defined below) at the beginning of a telephone conversation,”; (ii) by capitalizing the word “each” in the first sentence; and (iii) replacing the words “Parties to this Master Agreement” with “Parties’ trading and marketing personnel”. A new Section 2.6 is added to read as follows: “2.6 Imaged Agreement. Any original executed Transition Master Agreement, Confirmation or other related document may be photocopied and stored on computer tapes and disks (the ‘Imaged Agreement’). The Imaged Agreement, if introduced as evidence on paper, the Confirmation, if introduced as evidence in automated facsimile form, the Recording, if introduced as evidence in its original form and as transcribed onto paper or into other written format, and all computer records of the foregoing, if introduced as evidence in printed format, in any judicial, arbitration, mediation or administrative proceedings, will be admissible as between the Parties to the same extent and under the same conditions as other business records originated and maintained in documentary form. Neither Party shall object to the admissibility of the Recording, the Confirmation, or the Imaged Agreement (or photocopies of the transcription of the Recording, the Confirmation, or the Imaged Agreement) on the basis that such were not originated or maintained in documentary or written form under either the hearsay rule or the best evidence rule. However, nothing in this Section 2.6 shall preclude a Party from challenging the admissibility of such evidence on some other grounds, including, without limitation, the basis that such evidence has been materially or substantially altered from the original.” A new Section 2.7 is added to read as follows: “2.7 Conditions Precedent. (a) Within sixty (60) days of the Effective Date, Party B and Party A shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Party A nor Party B shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Party A the authority to sell the Product to Party B at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within thirty (30) calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Party B shall make best efforts to provide Party A with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within fifty (50) days after the Effective Date; provided that if Party B is unable to provide Party A with a draft of the public version of such independent evaluator report within 50 days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Party B provides Party A such independent evaluator report. (b) Within sixty (60) days after the Effective Date, Party B shall file with the CPUC the appropriate request for CPUC Approval. Party B shall

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expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Party A shall use reasonable efforts to support Party B in obtaining CPUC Approval. Party B has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party. (c) Notwithstanding Party A’s and Party B’s execution and delivery of this Agreement, no Transaction under this Agreement will be permitted or deemed valid until the Parties obtain FERC Approval and Party B obtains CPUC Approval. (d) Notwithstanding anything to the contrary set forth in this Agreement, no Transaction under this Agreement will be permitted or deemed valid until all of the condition precedents set forth in the Transition PPA have been satisfied or waived in accordance with the terms of the Transition PPA.” A new Section 2.8 is added to read as follows: “2.8 Termination Rights of the Parties; Automatic Termination. (a) If the Transition PPA is terminated before the commencement of the Term Start Date of the Transition PPA (including if such termination is due to the inability to obtain FERC Approval or CPUC Approval), then this Agreement (including any Transaction and related Confirmation entered into between Party A and Party B as of the Effective Date) will automatically terminate on the date of the termination of the Transition PPA.” ARTICLE THREE: OBLIGATIONS AND DELIVERIES. Amend Article Three as follows: A new Section 3.4 is added to read as follows: “3.4 Index Transactions. If the Contract Price for a Transaction is determined by reference to an index, then the following provisions shall be applicable to such Transaction. (a)

Market Disruption. If a Market Disruption Event occurs during a Determination Period, the Floating Price for the affected Trading Day(s) shall be determined by reference to the Floating Price specified in the Transaction for the first Trading Day thereafter on which no Market Disruption Event exists; provided, however, if the Floating Price is not so determined within three (3) Business Days after the first Trading Day on which the Market Disruption Event occurred or existed, then the Parties shall negotiate in good faith to agree on a Floating Price (or a method for determining a Floating Price), and if the Parties have not so agreed on or before the twelfth Business Day following the first Trading Day on which the Market Disruption Event occurred or existed, then the Floating Price shall be determined in good faith by taking the average of the price quotations for the relevant commodity and relevant Business Days that are obtained from no more than two (2) Reference Market-Makers selected by each Party.

(b) For purposes of this Section 3.4, the following definitions shall apply:

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(i) ‘Determination Period’ means each calendar month a part or all of which is within the Delivery Period of a Transaction. (ii) ‘Exchange’ means, in respect of a Transaction, the exchange or principal trading market specified in the relevant Transaction. (iii) ‘Floating Price’ means a price per unit in $U.S. specified in a Transaction that is based upon a Price Source. (iv) ‘Market Disruption Event’ means, with respect to any Price Source, any of the following events: (a) the failure of the Price Source to announce or publish the specified Floating Price or information necessary for determining the Floating price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading in the relevant options contract or commodity on the Exchange or in the market specified for determining a Floating Price; (c) the temporary or permanent discontinuance or unavailability of the Price Source; (d) the temporary or permanent closing of any Exchange specified for determining a Floating Price; or (e) a material change in the formula for or the method of determining the Floating Price. (v) ‘Price Source’ means, in respect of a Transaction, the publication (or such other origin of reference, including an Exchange) containing (or reporting) the specified price (or prices from which the specified price is calculated) specified in the relevant Transaction. (vi) ‘Trading Day’ means a day in respect of which the relevant Price Source published the Floating Price. (c) Corrections to Published Prices. For purposes of determining a Floating Price for any day, if the price published or announced on a given day and used or to be used to determine a relevant price is subsequently corrected and the correction is published or announced by the person responsible for that publication or announcement within twelve (12) months of the original publication or announcement, either Party may notify the other Party of (i) that correction and (ii) the amount (if any) that is payable as a result of that correction. If, not later than thirty (30) days after publication or announcement of that correction, a Party gives notice that an amount is so payable, the Party that originally either received or retained such amount will, not later than ten (10) Business Days after the effectiveness of that notice, pay, subject to any applicable conditions precedent, to the other Party that amount, together with interest at the Interest Rate for the period from and including the day on which payment originally was (or was not) made to but excluding the day of payment of the refund or payment resulting from that correction. (d) Calculation of Floating Price. For the purposes of the calculation of a Floating Price, all numbers shall be rounded to three (3) decimal places. If the fourth (4th) decimal number is five (5) or greater, then the third (3rd) decimal number shall be increased by one (1), and if the fourth (4th) decimal number is less than five (5), then the third (3rd) decimal number shall remain unchanged.” ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES. Amend Article Five as

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follows: Section 5.1(a) is amended by replacing “three (3) Business Days” with “five (5) Business Days”. Section 5.1(e) is amended by adding after the word “hereof” the phrase “or any other credit arrangement, including, but not limited to, the Collateral Annex (the ‘Transition Collateral Annex’) (or any similar agreement) related to this Agreement”. Section 5.1(f) is amended to read as follows: “(f) a Merger Event occurs with respect to such Party or its Guarantor, if applicable;” Section 5.1(h)(iv) is amended by inserting the words “made in connection with this Agreement” after the first instance of the word “guaranty”. Section 5.1(h)(v) is amended by inserting the words “made in connection with this Agreement” after the word “guaranty”. Section 5.1 is amended by adding the following Sections 5.1(i) and 5.1(j) at the end thereof: “(i) an event of default occurs (howsoever determined) under a Specified Energy Transaction (including under the Transition PPA) with respect to such Party and, after giving effect to any applicable notice requirement or grace period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that Specified Energy Transaction; or (j) the Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, this Transition Master Agreement, any Confirmation executed and delivered by that Party, the Transition PPA or any Transaction evidenced by such a Confirmation.” Section 5.2 is amended by (i) inserting “(a)” at the beginning thereof; (ii) reversing the placement of “(i)” and “to”; (iii) inserting after the words “designate a day” the words “and time of day” in clause (i) thereof; (iv) replacing the phrase “as soon thereafter as is reasonably practicable)” with “, then each such Transaction — individually, an ‘Excluded Transaction’ and collectively, the ‘Excluded Transactions’— shall be terminated as soon thereafter as is reasonably practicable, and upon termination shall be deemed to be a Terminated Transaction) and the Termination Payment payable in connection with all Terminated Transactions shall be calculated in accordance with this Section 5.2 and with Section 5.3 below”; and (v) adding the following paragraph at the end thereof: “(b) The Non-Defaulting Party shall determine its Gains and Losses by determining the Market Quotation Average Price for each Terminated Transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts, to obtain the Market Quotation Average Price with respect to any Terminated Transaction, then the NonDefaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner by calculating the arithmetic mean of at least three (3) Forward Price Assessments for transactions substantially similar to each Terminated Transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts to obtain at least three (3) Forward Price Assessments with respect to any Terminated Transaction, then the Non-Defaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a

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commercially reasonable manner by reference to information supplied to it by one or more third parties including, without limitation, index prices, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads, or other relevant market data in the relevant markets; provided, however, that the provider of such information shall not be an Affiliate of either Party. Only in the event the Non-Defaulting Party is not able, after using commercially reasonable efforts, to obtain such third party information, then the Non-Defaulting Party may calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner using relevant market data it has available to it internally.” Section 5.3 is amended by (i) deleting the “:” in the second line thereof; (ii) replacing the words “Agreement against” with “Agreement, against” immediately before “(b)”; and (iii) inserting the phrase “any cash then available to the Defaulting Party pursuant to Article Eight,” between the words “Non-Defaulting Party,” and “plus any” in the sixth line thereof. Section 5.4 is amended by inserting the phrase “but in no event more than fifteen (15) Business Days following the Early Termination Date,” after the phrase “liquidation,” in the second line thereof. Section 5.6 Option A is amended by (i) inserting the following phrase “with respect to the Specified Energy Transactions,” before the words “and/or (ii)” and (ii) adding the following at the end thereof : “Notwithstanding anything to the contrary contained in this Transition Master Agreement, or in any other agreement, instrument, or undertaking between the Parties with respect to a Specified Energy Transaction, if an Early Termination Date has been designated pursuant to Section 5.2, then, in addition to the other remedies provided in this Transition Master Agreement, the Non-Defaulting Party may accelerate, liquidate and terminate all, but not less than all, Specified Energy Transactions between the Parties.” Section 5.7 is amended to capitalize the word “early” in line 6 to read “Early”. ARTICLE SIX: PAYMENT AND NETTING. Amend Article Six as follows: Section 6.3 is amended to read as follows: “6.3 Disputes and Adjustments of Invoices. A Party may adjust any invoice rendered by it under this Agreement to correct any arithmetic or computational error or to include additional charges or claims within twenty-four (24) months after the close of the month in which the obligations being invoiced arose. A receiving Party may, in good faith, dispute the correctness of any invoice or of any adjustment to any invoice previously rendered to it by providing notice to the other Party on or before the later of (i) twelve (12) months of the date of receipt of such invoice or adjusted invoice, or (ii) twenty-four (24) months after the close of the month in which the obligation being invoiced arose. Failure to provide such notice within the time frame set forth in the preceding sentence waives the dispute with respect to such invoice. A Party disputing all or any part of an invoice or an adjustment to an invoice previously rendered to it may pay only the undisputed portion of the invoice when due, provided such Party provides notice to the other Party of the basis for and amount of the disputed portion of the invoice that has not been paid. The disputed portion of the invoice must be paid within two (2) Business Days of resolution of the dispute, along

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with interest accrued at the Interest Rate from and including the original due date of the invoice to but excluding the date the disputed portion of the invoice is actually paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment but excluding the date repaid or deducted by the Party receiving such overpayment. An invoice can only be adjusted or amended after it was originally rendered within the twenty-four (24) month time frame set forth in the first sentence of this Section 6.3. If an invoice is not rendered within twentyfour (24) months after the close of the month in which the payment obligations arose, the right to payment for that month under this Agreement is waived.” Section 6.7 is amended to replace the phrase “Section 6.1” with the phrase “Section 6.2”. ARTICLE SEVEN: LIMITATIONS. Amend Article Seven as follows: Section 7.1 is amended to (i) delete the phrase “EXCEPT AS SET FORTH HEREIN” in the first sentence; and (ii) in the fifth sentence (a) replace in its entirety the phrase “UNLESS EXPRESSLY HEREIN PROVIDED” with “NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY”; (b) add the following phrase “SET FORTH IN THIS AGREEMENT” after the words “INDEMNITY PROVISION”; and (c) add the following phrase “; PROVIDED, HOWEVER, THAT NOTHING IN THIS PROVISION SHALL AFFECT THE ENFORCEABILITY OF SECTIONS 5.2 AND 5.3 OF THIS AGREEMENT” after the words “OR OTHERWISE”. ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS. Amend Article Eight as follows: Section 8.1(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes) after the words “consolidated financial statements” in the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations, provided however, for the purposes of this (i) and (ii), if Party B’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party B’s website, then Party B shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line. Section 8.2(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes)” after the words “consolidated financial statements” in the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year end audit adjustments), provided however, for the purposes of

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this (i) and (ii), if Party A’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party A’s website, then Party A shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line; and (v) at the end thereof the phrase “For purposes of this Section, ‘Responsible Officer’ shall mean the Executive Director, Treasurer or any Assistant Treasurer of Party A or any employee of Party A designated by any of the foregoing.”. A new Section 8.4 is added to read as follows: “8.4 California Commercial Code Waiver. This Agreement and the Transition Collateral Annex set forth the entirety of the agreement of the Parties regarding credit, collateral and adequate assurances, in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement. Except as expressly set forth in the options elected by the Parties in respect of Sections 8.1 and 8.2, in Section 8.3, and in the relevant portions of the Transition Collateral Annex, neither Party: (a) has or will have any obligation to post margin, provide letters of credit, pay deposits, make any other prepayments or provide any other financial assurances, in any form whatsoever, or (b) will have reasonable grounds for insecurity with respect to the creditworthiness of a Party that is complying with the relevant provisions of Section 8 of this Transition Master Agreement and of the relevant provisions of the Transition Collateral Annex; in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement, and all implied rights relating to financial assurances arising from California Commercial Code Section 2609 or case law applying similar doctrines, are hereby waived.” ARTICLE NINE: GOVERNMENTAL CHARGES. Amend Article Nine as follows: Section 9.2, is amended to add the words “, charges, or fees” after the word “taxes” in the first line thereof. ARTICLE TEN: MISCELLANEOUS. Amend Article Ten as follows: Section 10.2(vi) is amended to add the phrase “(for purposes of this Section 10.2(vi), Party B shall be deemed to have no Affiliates)” after the word “Affiliates”. Section 10.2(x) is amended to read as follows: “(x) it is an ‘eligible commercial entity’ within the meaning of Section 1a (11) of the Commodity Exchange Act, as amended by the Commodity Futures Modernization Act of 2000 (the ‘Commodity Exchange Act’);” Section 10.2(xi) is amended to read as follows: “(xi) it is an ‘eligible contract participant’ within the meaning of Section 1a (12) of the Commodity Exchange Act; and ” Section 10.2(xii) is amended to read as follows: “(xii) each Transaction that is not executed or traded on a ‘trading facility’, as defined in Section 1(a)(33) of the Commodity Exchange Act, is subject to individual negotiation by the Parties.”

15

Section 10.4 is amended by adding the following sentence at the end thereof: “Neither Party shall be liable with respect to any Claim to the extent that such Claim resulted from the negligence, willful misconduct, or bad faith of the indemnified Party.” Section 10.5 is amended as follows: (a) add the following phrase to the end of clause (i) immediately after the word “arrangements” the phrase “to any person or entity whose creditworthiness is equal to or higher than that of such Party”; (b) in clause (ii) replace the words “affiliate” and “affiliate’s” with, respectively “Affiliate” and “Affiliate’s”; and (c) in clause (iii) immediately after the words “substantially all of the assets” insert the words “of such Party and”. Section 10.6 is amended to read as follows: “10.6 Governing Law; Venue; Dispute Resolution. (a) Governing Law and Venue. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY DISPUTE ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT. The Parties hereby consent to conduct all dispute resolution, judicial actions or proceedings arising directly, indirectly or otherwise in conjunction with, out of, related to, or arising from this Agreement in Los Angeles County, California. (b) Dispute Resolution. Any and all disputes, Claims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which Disputes the Parties have been unable to resolve by informal methods, will first be submitted to mediation in accordance with the procedures described in Section 10.6(c), and if the Dispute is not resolved through mediation, then for final and binding arbitration in accordance with the procedures described in Section 10.6(d). (c) Mediation. Either Party may initiate mediation by providing notice to the other Party of a written request for mediation, setting forth a description of the Dispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the panel of neutrals from the Judicial Arbitration and Mediation Services, Inc. or any successor entity (“JAMS”), or any other mutually acceptable non-JAMS Mediator, and such proceedings shall be conducted in accordance with the laws of the State of California, without regards to principles of conflicts of laws. Such selection and scheduling will be completed within forty-five (45) days after notice of the request for mediation. Unless the Parties agree to a different arrangement, the place of the mediation shall be in Los Angeles County, California. Unless otherwise agreed to by the Parties, the mediation will not be scheduled for a date that is greater than one-hundred twenty (120) days from the date of notice of the request for mediation. The Parties covenant that they will participate in the mediation in good faith, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and

16

costs will be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, will not be subject to discovery and will be confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them; provided, however, that evidence that is otherwise admissible or discoverable will not be rendered inadmissible or non-discoverable as a result of its use in the mediation. (d) Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation in accordance with Section 10.6(c) by providing notice of a demand for binding arbitration before a single, neutral arbitrator (the “Arbitrator”) at any time following the unsuccessful conclusion of the mediation provided for in Section 10.6(c). The Parties will cooperate with one another in selecting the Arbitrator within sixty (60) days after notice of the demand for arbitration and will further cooperate in scheduling the arbitration hearing to commence no later than one-hundred eighty (180) days from the date of notice of the demand. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator will be appointed as provided for in California Code of Civil Procedure Section 1281.6, in which case each candidate for Arbitrator must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator will be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon notice of a Party’s demand for binding arbitration, such Dispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, will be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regard to principles of conflicts of laws. Except as provided for in this Section 10.6(d), the arbitration will be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated. Absent the existence of such rules and procedures, the arbitration will be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration will be in Los Angeles, California, and discovery will be limited as follows: (i) before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment); (ii) the initial disclosure will occur within thirty (30) days after the initial conference with the Arbitrator or at such time as the Arbitrator may order; (iii) discovery may commence at any time after the Parties’ initial disclosure; (iv) the Parties will not be permitted to propound any interrogatories or requests

17

for admissions; (v) discovery will be limited to twenty-five (25) document requests (with no subparts), three (3) lay witness depositions, and three (3) expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents); (vi) each Party is allowed a maximum of three (3) expert witnesses, excluding rebuttal experts; (vii) Within sixty (60) days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding; (viii) within thirty (30) days after the initial expert disclosure, the Parties may designate a maximum of two (2) rebuttal experts; (ix) unless the Parties agree otherwise, all direct testimony will be in form of affidavits or declarations under penalty of perjury; and (x) each Party shall make available for crossexamination at the arbitration hearing its witnesses whose direct testimony has been so submitted. The Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections3.01, 3.02, 3.03, 9.09 of the Transition PPA. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator must, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs will be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail. Until such award is made, however, the Parties will share equally in paying the costs of the arbitration.” Section 10.8 is amended to replace in the penultimate sentence thereof the phrase “twelve (12) months” with the phrase “two (2) years”. Section 10.10 is amended to read as follows: “10.10 Bankruptcy Issues. The Parties intend that (i) all Transactions constitute a ‘forward contract’ within the meaning of the United States Bankruptcy Code (the ‘Bankruptcy Code’) or a ‘swap agreement’ within the meaning of the Bankruptcy Code; (ii) all payments made or to be made by one Party to the other Party pursuant to this Agreement constitute ‘settlement payments’ within the meaning of the Bankruptcy Code; (iii) all transfers of Performance Assurance by one Party to the other Party under this Agreement constitute ‘margin payments’ within the meaning of the Bankruptcy Code and (iv) this Agreement constitutes a ‘master netting agreement’ within the meaning of the Bankruptcy Code. Each Party further agrees that, for purposes of this Agreement, the other Party is not a ‘utility’ as such term is used in 11 U.S.C. Section 366, and each Party waives and agrees not to assert the applicability of the provisions of 11 U.S.C. Section 366 in any bankruptcy proceeding wherein such Party is a debtor. In any such proceeding, each Party further waives the right to assert that the other Party

18

is a provider of last resort to the extent such term relates to 11 U.S.C. Section 366 or another provision of 11 U.S.C. Section 101-1532.” Section 10.11 is amended to read as follows: “10.11 Confidentiality. If the Parties have elected on the Cover Sheet of the Transition Master Agreement to make this Section 10.11 applicable to this Transition Master Agreement, neither Party shall disclose the terms or conditions of this Agreement to a third party (other than the Party’s or the Party’s Affiliates’ officers, directors, employees, lenders, counsel, accountants, advisors, or rating agencies who have a need to know such information and have agreed to keep such terms confidential) except (i) in order to comply with any applicable law, order, regulation, ruling, summons, subpoena, exchange rule, or accounting disclosure rule or standard, or to make any showing required by any applicable governmental authority; (ii) to the extent necessary for the enforcement of this Agreement or to implement any Transaction; (iii) as may be obtained from a non-confidential source that disclosed such information in a manner that did not violate its obligations to the non-disclosing Party or its Guarantor in making such disclosure; (iv) to the extent such disclosure to a third party is for the sole purpose of calculating a published index, so long as such third party (1) has agreed prior to the disclosure to protect the specific information disclosed from public disclosure and (2) is a party engaged in the business of collecting such information for the purpose of establishing, creating, or formulating a published index; (v) to the extent such information is or becomes generally available to the public prior to such disclosure by a Party; (vi) when required to be released in connection with any regulatory proceeding (provided that the releasing Party makes reasonable efforts to obtain confidential treatment of the information being released); or (vii) with respect to Party B, as may be furnished to its duly authorized regulatory and governmental agencies or entities, including without limitation the California Public Utilities Commission (the “CPUC”) and all divisions thereof, and to Party B’s Procurement Review Group (the “PRG”), a group of participants including members of the CPUC and other governmental agencies and consumer groups established by the CPUC in D.02-08-071 and D.03-06-071. The existence of this Agreement is not subject to this confidentiality obligation; provided that neither Party shall make any public announcement relating to this Agreement unless required pursuant to subsection (i) or (vi) of the foregoing sentence of this Section 10.11. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation. With respect to information provided in connection with a Transaction, this obligation shall survive for a period of three (3) years following the expiration or termination of such Transaction. With respect to information provided under this Agreement, this obligation shall survive for a period of three (3) years following the expiration or termination of this Agreement. For the purposes of this Section 10.11, “Affiliate” for Party A shall mean Chevron Corporation, Chevron U.S.A. Inc., Chevron Kern River Cogeneration Company, Western Sierra Energy Company and Edison Mission Energy and “Affiliate” for Party B shall mean Edison International; provided, however, that for Party A, "Affiliate" shall not apply to the power marketing or trading personnel of Chevron Corporation, Chevron U.S.A. Inc., Chevron Kern River Cogeneration Company, Western Sierra Energy Company or Edison Mission Energy.” New Sections 10.12 and 10.13 shall be added as follows: “10.12

No Agency.

19

In performing their respective obligations hereunder,

neither Party is acting, or is authorized to act, as agent of the other Party.” “10.13 Mobile Sierra Doctrine. (a) Absent the agreement of all Parties to the proposed change, the standard of review for changes to any rate, charge, classification, term or condition of this Agreement, whether proposed by a Party (to the extent that any waiver in subsection (b) below is unenforceable or ineffective as to such Party), a non-party or FERC acting sua sponte, shall be the ‘public interest’ standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the ‘Mobile Sierra’ doctrine). (b) Notwithstanding any provision of Agreement, and absent the prior written agreement of the Parties, each Party, to the fullest extent permitted by Applicable Laws, for itself and its respective successors and assigns, hereby also expressly and irrevocably waives any rights it can or may have, now or in the future, whether under Sections 205, 206, or 306 of the Federal Power Act or otherwise, to seek to obtain from FERC by any means, directly or indirectly (through complaint, investigation, supporting a third party seeking to obtain or otherwise), and each hereby covenants and agrees not at any time to seek to so obtain, an order from FERC changing any Section of this Agreement specifying any rate or other material economic terms and conditions agreed to by the Parties.” SCHEDULE P: PRODUCTS AND DEFINITIONS. Amend Schedule P as follows: The following definitions are added: “ ‘CAISO Energy’ means with respect to a Transaction, a Product under which the Seller shall sell and the Buyer shall purchase a quantity of energy equal to the hourly quantity without Ancillary Services (as defined in the Tariff) that is or will be scheduled as a schedule coordinator to schedule coordinator transaction pursuant to the applicable tariff and protocol provisions of the CAISO (as amended from time to time, the ‘Tariff’) for which the only excuse for failure to deliver or receive is an Uncontrollable Force (as defined in the Tariff).” The following products are added: “Other Products and Service Levels. If the Parties agree to a service level or product defined by a different agreement, set of rules, tariff, or protocol (herein, the ‘agreement’) (i.e., the WSPP Agreement) for a particular Transaction, then, unless the Parties expressly state and agree that all the terms and conditions of such other agreement will apply, such reference to a service level or product defined by such other agreement means that the service level or product for that Transaction is subject to the applicable regional independent system operator and/or utility reliability requirements and guidelines as well as the permitted excuses for performance, Force Majeure, Uncontrollable Forces, or other such excuses applicable to performance under such other agreement, to the extent inconsistent with the terms of this Agreement, provided, however, that all other terms and conditions of this Agreement shall and do remain applicable including, without limitation, Section 2.2; and provided, further that with respect to any Transaction for a product or service level defined by such other agreement, the methodology for

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SCHEDULE 1 – Form of Letter of Credit ISSUE DATE: L/C NO.: __________________ ACCOUNT PARTY: ACCOUNT NAME ADDRESS CITY, STATE XXXXX-XXXX BENEFICIARY NAME ADDRESS CITY, STATE XXXXX-XXXX

AMOUNT: USD XXXX.00 (XXX AND 00/100 UNITED STATES DOLLARS)

WE HEREBY ESTABLISH THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT NO. ______________ FOR AN AGGREGATE AMOUNT NOT TO EXCEED THE AMOUNT INDICATED ABOVE, EXPIRING AT OUR COUNTERS WITH OUR CLOSE OF BUSINESS ON (DATE). THIS LETTER OF CREDIT IS AVAILABLE WITH (BANK NAME), AGAINST PRESENTATION OF YOUR DRAFT AT SIGHT DRAWN ON (BANK NAME), WHEN ACCOMPANIED BY: 1) THE ORIGINAL OF THIS LETTER OF CREDIT (OR A PHOTOCOPY OF THE ORIGINAL FOR PARTIAL DRAWINGS) AND ANY SUBSEQUENT AMENDMENTS, IF ANY; AND 2) A DRAW CERTIFICATE (SEE EXHIBIT A) PURPORTEDLY SIGNED BY ONE OF THE BENEFICIARY’S REPRESENTATIVES. BENEFICIARY SHALL BE ENTITLED TO DRAW UPON THIS LETTER OF CREDIT UP TO THE STATED AMOUNT, IN ONE OR MORE DRAWINGS; PROVIDED HOWEVER, THAT IF ANY DRAWING WOULD EXCEED THE STATED AMOUNT, BENEFICIARY SHALL BE ENTITLED TO DRAW ONLY THAT PORTION THAT WOULD NOT EXCEED THE STATED AMOUNT. ALL CORRESPONDENCE AND ANY DRAWINGS HEREUNDER ARE TO BE DIRECTED TO (BANK ADDRESS/CONTACT). WE HEREBY AGREE WITH YOU THAT DRAFTS DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS AND CONDITIONS OF THIS LETTER OF CREDIT WILL BE DULY HONORED. THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT IS ISSUED SUBJECT TO THE INTERNATIONAL STANDBY PRACTICES 1998, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 590 (ISP98) AND AS TO MATTERS NOT ADDRESSED BY THE ISP98 THIS LETTER OF CREDIT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICT OF LAWS. THE NUMBER AND THE DATE OF OUR CREDIT AND THE NAME OF OUR BANK MUST BE QUOTED ON ALL DRAFTS REQUIRED.

EXHIBIT A DRAW CERTIFICATE AN “EVENT OF DEFAULT” OR “EARLY TERMINATION DATE” (AS DEFINED IN SECTION 5 OF THE EDISON ELECTRIC INSTITUTE MASTER POWER PURCHASE & SALE AGREEMENT VERSION 2.1 AS MODIFIED ON 4/25/00 BETWEEN ACCOUNT PARTY AND BENEFICIARY, DATED _____________________ (THE “POWER PURCHASE AND SALE AGREEMENT”)) HAS OCCURRED AND IS CONTINUING WITH RESPECT TO THE ACCOUNT PARTY UNDER THIS LETTER OF CREDIT. WHEREFORE, THE UNDERSIGNED DOES HEREBY DEMAND PAYMENT TO THE UNDERSIGNED OF $USD (INSERT AMOUNT) BUT NOT TO EXCEED THE REMAINING UNDRAWN AMOUNT OF THE LETTER OF CREDIT. THE AMOUNT DEMANDED UNDER THIS LETTER OF CREDIT HAS BEEN COMPUTED IN ACCORDANCE WITH THE POWER PURCHASE AND SALE AGREEMENT.

(COMPANY NAME)

By: (SIGNATURE OF COMPANY REPRESENTATIVE) Title: _____________________________________

DATED: _________________________

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between SOUTHERN CALIFORNIA EDISON COMPANY and KERN RIVER COGENERATION COMPANY (RAP ID #2811)

Transition Standard Contract for Existing Qualifying Cogeneration Facilities

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

TABLE OF CONTENTS LIST OF EXHIBITS .......................................................................................................... iv  PREAMBLE ........................................................................................................................1  RECITALS ..........................................................................................................................1  ARTICLE ONE:  SPECIAL CONDITIONS ................................................................3  1.01  Term ................................................................................................................3  1.02  Generating Facility..........................................................................................3  1.03  Delivery Point .................................................................................................4  1.04  Capacity Performance Requirements ..............................................................5  1.05  Maintenance Outages; Major Overhaul ..........................................................5  1.06  Power Product Prices ......................................................................................5  1.07  [Intentionally omitted.] ...................................................................................6  1.08  Scheduling Coordinator Election ....................................................................6  ARTICLE TWO: SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION ......................................................7  2.01  Seller’s Satisfaction of Obligations before the Term Start Date.....................7  2.02  Termination Rights of the Parties ...................................................................8  2.03  Rights and Obligations Surviving Termination ..............................................9  2.04  CPUC Filing and Approval of this Agreement .............................................10  2.05  FERC Filing and Approval ...........................................................................10  2.06  Commencement of Term under Confirmations ............................................11  ARTICLE THREE:  SELLER’S OBLIGATIONS .........................................................12  3.01  Conveyance of the Product; Retained Benefits ............................................12  3.02  Resource Adequacy Rulings .........................................................................13  3.03  Site Control ...................................................................................................14  3.04  Permits ..........................................................................................................14  3.05  Transmission .................................................................................................14  3.06  CAISO Relationship .....................................................................................15  3.07  Generating Facility Modifications ...............................................................15  3.08  Metering ........................................................................................................17  3.09  Telemetry System .........................................................................................18  3.10  Provision of Information ...............................................................................19  3.11  [Intentionally omitted.] .................................................................................20  3.12  Fuel Supply ...................................................................................................20  3.13  Demonstrations .............................................................................................20  3.14  Operation and Record Keeping .....................................................................20  3.15  Power Product Curtailments at Transmission Provider’s or CAISO’s Request ..........................................................................................................22  3.16  Report of Lost Output ...................................................................................23  3.17  FERC Qualifying Cogeneration Facility Status ............................................24  3.18  Notice of Cessation or Termination of Service Agreements ........................25  3.19  Buyer’s Access Rights ..................................................................................25  3.20  Seller Financial Information .........................................................................25  3.21  NERC Electric System Reliability Standards ...............................................28 

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i

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

3.22 

Allocation of Availability Incentive Payments and Non-Availability Charges .........................................................................................................29  3.23  Seller’s Reporting Requirements .................................................................30  ARTICLE FOUR:  BUYER’S OBLIGATIONS...........................................................31  4.01  Obligation to Pay ..........................................................................................31  4.02  Payment Adjustments ...................................................................................31  4.03  Payment Statement and Payment ..................................................................32  4.04  GHG Compliance Costs................................................................................35  4.05  No Representation by Buyer .........................................................................35  4.06  Buyer’s Responsibility ..................................................................................35  4.07  Buyer’s Reporting Requirements ..................................................................35  ARTICLE FIVE:  FORCE MAJEURE .......................................................................36  5.01  No Default for Force Majeure.......................................................................36  5.02  Requirements Applicable to the Claiming Party ..........................................36  5.03  Termination ...................................................................................................36  ARTICLE SIX:  EVENTS OF DEFAULT; REMEDIES .........................................37  6.01  Events of Default ..........................................................................................37  6.02  Early Termination .........................................................................................40  6.03  Termination Payment ....................................................................................40  ARTICLE SEVEN:  LIMITATIONS OF LIABILITIES ................................................42  ARTICLE EIGHT:  GOVERNMENTAL CHARGES...................................................44  8.01  Cooperation to Minimize Tax Liabilities ......................................................44  8.02  Governmental Charges..................................................................................44  8.03  Providing Information to Taxing Governmental Authorities .......................44  ARTICLE NINE:  MISCELLANEOUS ......................................................................45  9.01  Representations and Warranties ....................................................................45  9.02  Additional Representations, Warranties, and Covenants by Seller ..............46  9.03  Indemnity ......................................................................................................46  9.04  Assignment ...................................................................................................48  9.05  Consent to Collateral Assignment ................................................................49  9.06  Governing Law and Jury Trial Waiver .........................................................52  9.07  Notices ..........................................................................................................52  9.08  General ..........................................................................................................53  9.09  Confidentiality ..............................................................................................54  9.10  Insurance .......................................................................................................56  9.11  Nondedication ...............................................................................................58  9.12  Mobile Sierra ................................................................................................59  9.13  Seller Ownership and Control of Generating Facility ..................................59  9.14  Simple Interest Payments ..............................................................................59  9.15  Payments .......................................................................................................59  9.16  Provisional Relief..........................................................................................59  ARTICLE TEN:  DISPUTE RESOLUTION .............................................................61  10.01  Dispute Resolution ........................................................................................61  10.02  Mediation ......................................................................................................61 

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ii

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

10.03  Arbitration .....................................................................................................61  SIGNATURES...................................................................................................................64 

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iii

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

LIST OF EXHIBITS A.

Definitions

B.

Generating Facility and Site Description

C.

[Intentionally omitted]

D.

Monthly Contract Payment Calculation

D-1.

Force Majeure Credit Value

D-2.

Transmission Curtailment Credit Value

E.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

F.

[Intentionally omitted]

G.

Scheduling Coordinator Services

H.

[Intentionally omitted]

I.

Seller’s Forecasting Submittal and Accuracy Requirements

J.

CAISO Charges

K.

Scheduling and Delivery Deviation Adjustments

L.

Physical Trade Settlement Amount

M.

SC Trade Settlement Amount

N.

Notice List

O.

[Intentionally omitted]

P.

[Intentionally omitted]

Q.

[Intentionally omitted]

R.

Outage Schedule Submittal Requirements

S.

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

T.

QF Efficiency Monitoring Program – Cogeneration Data Reporting Form

Table of Contents

iv

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between SOUTHERN CALIFORNIA EDISON COMPANY and KERN RIVER COGENERATION COMPANY (RAP ID #2811) PREAMBLE This Power Purchase and Sale Agreement by and between Southern California Edison Company, a California corporation (“Buyer”), and Kern River Cogeneration Company, a California general partnership (“Seller”), together with the exhibits, attachments, and any applicable referenced collateral agreement or similar arrangement between the Parties that is expressly incorporated into this Agreement by the Parties (collectively, this “Agreement”), is made, effective and binding as of October 15, 2012 (the “Effective Date”). Buyer and Seller are sometimes referred to in this Agreement individually as a “Party” and jointly as the “Parties.” Unless the context otherwise specifies or requires, initially capitalized terms used in this Agreement have the meanings set forth in Exhibit A. RECITALS A.

On or about September 20, 2007, the CPUC issued Decision (“D.”) 07-09-040 (the “Decision”) which, among other things, directed Buyer to develop a form of a standard contract and offer such contract to qualifying facilities meeting the eligibility criteria set forth in the Decision.

B.

Commencing in May 2009, Pacific Gas and Electric Company, San Diego Gas and Electric Company, Southern California Edison Company, the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, the Independent Energy Producers Association, the Division of Ratepayer Advocates of the California Public Utilities Commission, and The Utility Reform Network (collectively, the “Settling Parties”) entered into CPUC-facilitated settlement negotiations in order to resolve certain outstanding issues among the Settling Parties, including the implementation of the Decision.

Preamble; Recitals

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

C.

Pursuant to the settlement negotiations, the Settling Parties entered into that certain Settlement Agreement, dated October 8, 2010 (the “Settlement Agreement”), which resolved certain issues pending in Rulemakings 99-11-022, 04-04-003, 04-04-025, and 06-02-013, and Application 08-11-001.

D.

The Settlement Agreement became effective on November 23, 2011 (the “Settlement Effective Date”).

E.

Buyer is offering this Agreement to Seller in accordance with the requirements set forth in the Settlement Agreement, and Seller desires to enter into such Agreement.

G.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition EEI Agreement, including the Transition Tolling Confirmation and the Transition RA Confirmation.

H.

Pursuant to the terms and conditions set forth in the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation, Buyer will purchase from Seller and Seller will sell to Buyer the Product (as such term, in this instance only for purposes of this Agreement, is defined in each of the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation).

The Parties, intending to be legally bound, agree as follows:

Preamble; Recitals

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE ONE.

SPECIAL CONDITIONS

1.01

Term. The term of this Agreement (the “Term”) commences on the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained (the “Term Start Date”); provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Term shall not commence until all of the condition precedents set forth in each of the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Term Start Date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03)), and ends June 30, 2015 (the “Term End Date”). The Term Start Date must occur on the first day following the termination of Amended and Restated Parallel Generation Agreement between Kern River Cogeneration Company and Southern California Edison Company dated December 15, 2005, as amended by Amendment No. 1 dated May 30, 2006, and extended by letter agreement entered into pursuant D.07-09-040 dated June 28, 2012 (the “Existing PPA”).

1.02

Generating Facility. (a)

Name; Designation. The name of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation is Kern River Cogeneration Company, which is an Existing Qualifying Cogeneration Facility.

(b)

Location; Site. The Generating Facility is located at SW China Grade Loop, Bakersfield, CA 93308, and is further described in Exhibit B.

(c)

Qualifying Cogeneration Facility Type. As of the Effective Date, the Generating Facility, which includes the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation, is a “topping-cycle cogeneration facility”, as defined in 18 CFR Part 292, Section 292.202(d).

(d)

Contract Capacity. As set forth in the following table, Seller may elect (i) only Firm Contract Capacity, (ii) only As-Available Contract Capacity, or (iii) both Firm Contract Capacity and As-Available Contract Capacity: Month January February

Monthly Firm Contract Capacity (kW) 150,000 150,000

Article One

As-Available Contract Capacity (kW/) 4,000 4,000

Net Contract Capacity (kW) 154,000 154,000

Special Conditions

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company March April May June July August September October November December

149,000 145,000 142,000 141,000 140,000 141,000 142,000 144,000 146,000 148,000

5,000 9,000 12,000 13,000 14,000 13,000 12,000 10,000 8,000 6,000

154,000 154,000 154,000 154,000 154,000 154,000 154,000 154,000 154,000 154,000

Firm Contract Capacity, As-Available Contract Capacity and Net Contract Capacity are subject to adjustment in accordance with Section 3.07(c). Subject to adjustment in accordance with Section 3.07(c), the Firm Contract Capacity for all months of the year must be less than or equal to 150,000 kW, the As-Available Contract Capacity for all months of the year must be less than or equal to 14,000 kW, and the sum of Firm Contract Capacity and As-Available Contract Capacity for all months of the year must be less than or equal to 154,000 kW. (e)

1.03

Expected Term Year Energy Production. (i)

The Expected Term Year Energy Production for each Term Year equals 1,280,000,000 kWh.

(ii)

The Expected Term Year Energy Production may be revised in accordance with Section 3.07(c), or based on changes in the Site Host Load or the Site Host thermal requirements; provided, however, that such revision must be supported by a certification from a California-licensed professional engineer qualified to make a representation affirming that such revision is reasonable and based on (i) actual modifications to the Generating Facility performed or to be performed by Seller in accordance with and subject to Section 3.07(c), or (ii) changes in the Site Host Load or the Site Host thermal requirements. Such certification must include all data relied on to support the revised Expected Term Year Energy Production.

(iii)

Subject to adjustments in accordance with Section 1.02(e)(ii), the Expected Term Year Energy Production may never exceed 1,280,000,000 kWh in any Term Year.

Delivery Point. The delivery point is the point of delivery of the Power Product to the CAISO Controlled Grid which shall be between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal Magunden 230 kV line (the “Delivery Point”). Seller shall provide and convey to Buyer the Power Product from

Article One

Special Conditions

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

the Generating Facility at the Delivery Point. Title to and risk of loss related to the Power Product transfer from Seller to Buyer at the Delivery Point. 1.04

Capacity Performance Requirements. As further described in Exhibit D, if the Generating Facility elects to provide Firm Contract Capacity, then the Generating Facility must have a minimum Firm Contract Capacity performance requirement of 95% to earn the Maximum Firm Capacity Payment and a minimum Capacity Performance Requirement of 60% to earn any portion of the Maximum Firm Capacity Payment.

1.05

Maintenance Outages; Major Overhaul.

1.06

(a)

The total Maintenance Debit Value for Maintenance Outages, as determined in accordance with Exhibit E, may not exceed 550 hours in the first Term Year. At the end of each Term Year following the first Term Year, up to a maximum of 50 unused hours may be carried over to the following Term Year. For each of the Term Years after the first Term Year, the total Maintenance Debit Value for Maintenance Outages may not exceed 550 hours plus hours carried over from prior Term Years; provided, however, that such Maintenance Debit Value may not exceed 600 hours in any Term Year.

(b)

Seller may (i) request one Major Overhaul Allowance (in accordance with Exhibit E) of up to 750 total hours, (ii) schedule no more than one Major Overhaul; provided, however, that the Maintenance Debit Value for such Major Overhaul may not exceed 750 hours.

(c)

If Seller utilizes all of its Major Overhaul Allowance during a Major Overhaul, the remaining portion of the Major Overhaul may be converted to a Maintenance Outage as far as Maintenance Credit Value and Maintenance Debit Value are concerned; provided, however, that Seller submits a Notice to Buyer of such conversion within 60 days of the end of such Major Overhaul.

(d)

During the Peak Months, Seller may only schedule Maintenance Outages during the non-peak hours of such Peak Months, and the monthly Maintenance Debit Value for Maintenance Outages during the Peak Months may not exceed 12 nonpeak hours per Peak Month. Such limitation is part of, and not in addition to, the annual limits as set forth in Section 1.05(a).

Power Product Prices. (a)

Firm Capacity Price. The Firm Capacity Price equals $91.97 per kW-year.

(b)

As-Available Capacity Price. The As-Available Capacity Price is set forth in Section 3 of Exhibit D.

Article One

Special Conditions

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(c)

TOD Period Energy Price. The TOD Period Energy Price is set forth in Section 2 of Exhibit D.

1.07

[Intentionally omitted.]

1.08

Scheduling Coordinator Election. Buyer is the Scheduling Coordinator under this Agreement. Notwithstanding anything to the contrary set forth in this Agreement, Buyer must be the Scheduling Coordinator under this Agreement if Seller intends to utilize the exemptions set forth in, and subject to, Sections 3.06(b) or 3.09(b). *** End of Article One ***

Article One

Special Conditions

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE TWO.

2.01

SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION; CPUC AND FERC APPROVAL

Seller’s Satisfaction of Obligations before the Term Start Date. Seller shall satisfy each of the following obligations before the Term Start Date: (a)

The Generating Facility is a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(b)

Seller enters into all agreements, obtains all Governmental Authority approvals and Permits, and takes all steps necessary for it to: (i)

Operate the Generating Facility;

(ii)

Deliver electric energy from the Generating Facility to the Delivery Point; and

(iii)

Schedule, or arrange for a third party or Buyer to Schedule, the electric energy produced by the Generating Facility with the CAISO;

(c)

Seller’s Scheduling Coordinator, as set forth in Section 1.08, is authorized by the CAISO to Schedule the electric energy produced by the Generating Facility with the CAISO;

(d)

Seller satisfies its obligation to install the CAISO-Approved Meters, as set forth in this Agreement;

(e)

Seller furnishes to Buyer the insurance documents required under Section 9.10(c);

(f)

Seller is in compliance with the CAISO Tariff as set forth in this Agreement;

(g)

Seller enters into and fulfills all of its obligations under (i) the applicable interconnection agreements with the applicable Transmission Provider that are required to enable Parallel Operation of the Generating Facility with the interconnected electric system and the CAISO Controlled Grid, and (ii) any transmission, distribution or other service agreement that are required to enable Seller to transmit electric energy from the Generating Facility to the Delivery Point;

(h)

Seller furnishes to Buyer the documents required under Section 3.05; and

(i)

If Buyer is Scheduling Coordinator and the Generating Facility is PIRP-eligible, then the Generating Facility is certified as a PIRP resource by the CAISO.

Article Two

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

2.02

Termination Rights of the Parties. (a)

[Intentionally omitted.]

(b)

Termination Right of Seller.

(c)

Article Two

(i)

Seller has the right to terminate this Agreement if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected by Buyer in a competitive solicitation. In such an instance, the termination of this Agreement will be effective as of midnight the day before the commencement of any delivery period for any electric energy, capacity or attributes from the Generating Facility which is selected by Buyer in such competitive solicitation.

(ii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected in a competitive solicitation by a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 2.02(b)(ii) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

(iii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility jointly enter into an agreement for the sale of electric energy, capacity or attributes with a California investorowned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 2.02(b)(iii) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

Event of Default. In the event of an uncured Event of Default or an Event of Default for which there is no opportunity for cure permitted in this Agreement, the Non-Defaulting Party may, at its option, terminate this Agreement as set forth

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

in Section 6.02 and, if the Non-Defaulting Party is Buyer, then Seller (or any entity over which Seller or any owner or manager of Seller exercises control) agrees to waive any right it may have to enter into any new mandatory mustpurchase contract (including the Transition PPA, the QF PPA, or the Optional AsAvailable PPA, as such terms are defined in the Settlement Agreement) to sell electric energy, capacity or Related Products from the Generating Facility to Buyer or any other California investor-owned utility for a period of 365 days following the date of such termination. For purposes of this Section 2.02(c), “control” means the direct or indirect ownership of 20% or more of the outstanding capital stock or other equity interests having ordinary voting power.

2.03

(d)

End of Term. This Agreement automatically terminates at 11:59 p.m. PPT on the Term End Date.

(e)

Failure to Obtain CPUC Approval or FERC Approval. If CPUC Approval or FERC Approval has not been obtained by the Term End Date, this Agreement shall terminate in accordance with Section 2.02(d).

(f)

Termination of the Transition EEI Agreement. If the Transition EEI Agreement is terminated before the commencement of the Delivery Period of either the Transition Tolling Confirmation or the Transition RA Confirmation (as defined therein), then this Agreement will automatically terminate, without liability for a Forward Settlement Amount by either Party, on the date of the termination of the Transition EEI Agreement.

Rights and Obligations Surviving Termination. The rights and obligations of the Parties that are intended to survive a termination of this Agreement are all such rights and obligations that this Agreement expressly provides survive such termination as well as those rights and obligations arising from either Parties’ covenants, agreements, representations or warranties applicable to, or to be performed, at, before or as a result of the termination of this Agreement, including: (a)

The obligation of Buyer to make all outstanding Monthly Contract Payments for periods before termination of this Agreement;

(b)

The obligation of Buyer to invoice Seller for all payment adjustments for periods before termination of this Agreement, as set forth in Section 4.02;

(c)

The obligation of Seller to pay any Buyer payment-adjustment invoice described in Section 4.03(b) for periods before termination of this Agreement within 30 days of Seller’s receipt of such invoice;

(d)

The obligation of Buyer or Seller, as applicable, to make payments, if any, after the termination of this Agreement, as set forth in Section 3(c) of Exhibit S;

Article Two

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

2.04

2.05

(e)

The obligation to make a Termination Payment, as set forth in Section 6.03;

(f)

The indemnity obligations, as set forth in Section 9.03;

(g)

The obligation of confidentiality, as set forth in Section 9.09;

(h)

The right to pursue remedies under Section 6.02(c); and

(i)

The limitation of damages under Article Seven.

CPUC Filing and Approval of this Agreement. (a)

Within 60 days after the Effective Date, Buyer shall file with the CPUC the appropriate request for CPUC Approval. Buyer shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support Buyer in obtaining CPUC Approval. Buyer has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Before the Term Start Date, Buyer must have obtained or waived CPUC Approval.

FERC Filing and Approval. (a)

Article Two

Within 60 days of the Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Buyer provides Seller such independent evaluator report. (b)

2.06

Notwithstanding Seller’s and Buyer’s execution and delivery of this Agreement, this Agreement is subject to FERC Approval and the Term Start Date shall not occur until FERC Approval has been obtained.

Commencement of Term under Confirmations. Notwithstanding anything to the contrary set forth in this Agreement, the Term of this Agreement will not commence until the commencement of the Delivery Period of the Transition Tolling Confirmation and the Transition RA Confirmation (as defined respectively therein). *** End of Article Two ***

Article Two

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE THREE. SELLER’S OBLIGATIONS 3.01

Conveyance of the Product; Retained Benefits. (a)

Product. During the Term, Seller shall provide and convey the Product to Buyer in accordance with the terms of this Agreement, and Buyer shall have the exclusive right to the Product and all benefits derived therefrom, including the exclusive right to sell, convey, transfer, allocate, designate, award, report or otherwise provide any and all of the Product purchased under this Agreement and the right to all revenues generated from the use, sale or marketing of the Product.

(b)

Green Attributes. Seller hereby provides and conveys all Green Attributes associated with the Related Products as part of the Product being delivered during the Term. Seller represents and warrants that Seller holds the rights to all Green Attributes associated with the Related Products, and Seller agrees to convey and hereby conveys all such Green Attributes to Buyer as included in the delivery of the Product from the Project.

(c)

Further Action by Seller. Seller shall, at its own cost, take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term, which actions may include: (i)

Cooperating with the Governmental Authority responsible for resource adequacy administration to certify the Generating Facility for resource adequacy purposes;

(ii)

Testing the Generating Facility as may be required to certify the Generating Facility for resource adequacy purposes in accordance with the requirements set forth in the CAISO Tariff or as otherwise agreed to by the Parties;

(iii)

Committing to Buyer the Net Contract Capacity; and

(iv)

Complying with Applicable Laws regarding the registration, transfer or ownership of Green Attributes associated with the Related Products, including, if applicable to the Generating Facility, participation in WREGIS or other process recognized under Applicable Laws. With respect to WREGIS, at Buyer’s option, Seller shall cause and allow Buyer to be the “Qualified Reporting Entity” and “Account Holder” (as these two terms are defined by WREGIS) for the Generating Facility;

(v)

Complying with all CAISO Tariff requirements applicable to a Resource Adequacy Resource; and

Article Three

Seller’s Obligations

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(vi)

(d)

3.02

If Buyer is not the Scheduling Coordinator: 1)

Timely submitting, or causing Seller’s Scheduling Coordinator to timely submit, Supply Plans to identify and confirm the Net Qualifying Capacity of the Generating Facility sold to Buyer as a Resource Adequacy Resource; and

2)

Causing the Generating Facility’s Scheduling Coordinator to certify to Buyer, within 15 Business Days before the relevant deadline for any applicable RAR Showing or LAR Showing, that Buyer will be credited with the Net Qualifying Capacity of the Generating Facility for such RAR Showing or LAR Showing in the Generating Facility’s Scheduling Coordinator’s Supply Plan.

Retained Benefits. Seller shall retain for its own use or disposition all Financial Incentives and all attributes, benefits and credits associated with the Generating Facility and the electrical or thermal energy produced therefrom, other than the Power Product and the Related Products. Subject to Seller’s compliance with the applicable FERC rules and regulations, Seller may use, provide and convey any electric energy, capacity, Green Attributes, Capacity Attributes, Resource Adequacy Benefits, or any other product or benefit associated with the Generating Facility or the output thereof before the Term Start Date.

Resource Adequacy Rulings. During the Term, Seller shall grant, pledge, assign and otherwise commit to Buyer the generating capacity of the Generating Facility associated with the Related Products in order for Buyer to use in meeting its resource adequacy obligations under any Resource Adequacy Ruling. Seller: (a)

Has not used, granted, pledged, assigned or otherwise committed any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer for any portion of the Term;

(b)

Will not during the Term use, grant, pledge, assign or otherwise commit any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer; and

(c)

Shall take all reasonable actions (including complying with all current and future CAISO Tariff provisions and decisions of the CPUC or any other Governmental Authority that address Resource Adequacy Rulings) and execute all documents that are reasonable and necessary to effect the use of the generating capacity of the Generating Facility associated with the Related Products for Buyer’s sole benefit throughout the Term.

Article Three

Seller’s Obligations

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

3.03

Site Control. Seller shall have Site Control as of the earlier of: (a) the Term Start Date and (b) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term. Seller shall provide Buyer with prompt Notice of any change in the status of Seller’s Site Control.

3.04

Permits. Seller shall obtain and maintain any and all Permits necessary for the Operation of the Generating Facility and to deliver electric energy from the Generating Facility to the Delivery Point.

3.05

Transmission. (a)

Interconnection Studies. Seller has provided Buyer with true and complete copies of all Interconnection Studies received by Seller for the Generating Facility after the date that is 24 months before the Effective Date.

(b)

Seller’s Responsibility. Seller shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable Parallel Operation of the Generating Facility with the Transmission Provider’s electric system and the applicable Control Area operator’s electric grid and to effect Scheduling of the electric energy from the Generating Facility and transmission and delivery to the Delivery Point. Except as otherwise provided in its interconnection agreement, the CAISO Tariff, or the Transmission Provider’s tariff, rules or regulations, Seller shall pay all Transmission Provider charges or other charges directly caused by, associated with, or allocated to the following:

(c)

(i)

All required Interconnection Studies, facilities upgrades, and agreements;

(ii)

Interconnection of the Generating Facility to the Transmission Provider’s electric system;

(iii)

Any costs or fees associated with obtaining and maintaining a wholesale distribution access tariff agreement, if applicable; and

(iv)

The transmission and delivery of electric energy from the Generating Facility to the Delivery Point.

Acknowledgement. The Parties acknowledge and agree that any other agreement between Seller and Buyer, including any interconnection agreements, is separate and apart from this Agreement and does not modify or add to the Parties’ obligations under this Agreement, and that any Party’s breach under such other

Article Three

Seller’s Obligations

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

agreement does not excuse such Party’s nonperformance under this Agreement, except to the extent that such breach constitutes a Force Majeure under this Agreement. 3.06

3.07

CAISO Relationship. (a)

Throughout the Term, Seller shall comply with all applicable provisions of the CAISO Tariff (including complying with any exemption obtained from the CAISO pursuant to the CAISO Tariff), as determined by the CAISO, including securing and maintaining in full force all of the CAISO agreements, certifications and approvals required in order for the Generating Facility to comply with the applicable provisions of the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.06(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not installed one or more CAISO-Approved Meters for the Generating Facility on or before the Term Start Date, Seller will not be in breach of this Agreement with respect to such requirement to install CAISOApproved Meter(s) if Seller installs such CAISO-Approved Meter(s) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement to install CAISO-Approved Meter(s) by complying with a milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to Seller’s requirement that the CAISO-Approved Meters for the Generating Facility be installed on or before the Term Start Date, which extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request.

(c)

Buyer agrees that, subject to the limitation set forth in Section 3.06(b) and upon the CAISO’s request, pending the installation of the CAISO-Approved Meter(s) by Seller for the Generating Facility, Buyer shall provide to the CAISO any settlement quality meter data reasonably requested by the CAISO for settlement purposes.

Generating Facility Modifications. (a)

Seller is responsible for the design, procurement and construction of all modifications necessary for the Generating Facility to meet the requirements of this Agreement and to comply with any restriction set forth in any Permit.

Article Three

Seller’s Obligations

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(b)

(c)

Seller shall provide 30 days advance Notice to Buyer if there is any modification (other than a routine fluctuation in output or consumption) of the Generating Facility, the Site Host Load or operations related to the Site Host Load changing: (i)

Electric energy output by five percent of Expected Term Year Energy Production; or

(ii)

The type of Primary Fuel consumed by the Generating Facility.

Seller may not materially modify or repower the Generating Facility without prior written consent of Buyer; provided, however, that modifications or repowering will not be deemed material and is permitted under this Agreement without further consideration, other than Notices required under Section 3.07(b), if: (i)

Capacity added as a result of such modification or repower (including the addition of a steam turbine) over the Term is within the applicable MW limits set forth in the following table (for a Generating Facility with multiple turbines, the limits below are limits per turbine): Current Turbine Name Plate on the Effective Date

Increase to Turbine Name Plate Over the Term

10MW or Less

5MW

Greater than 10MW but less than 20MW

10MW

Greater than or equal to 20MW but less than 25MW

15MW

Greater than or equal to 25MW but less than 50MW

20MW

Greater than or equal to 50MW but less than 100MW

25MW

Greater than or equal to 100 but less than 200MW

35MW

Greater than or equal to 200 but less than 350MW

45MW

Greater than or equal 350MW

50MW

Or, (ii)

Such modification or repower is reasonably necessary to respond to a Force Majeure or a change in law or regulation, and a qualified Californialicensed professional engineer verifies that such modification or repower is not oversized relative to other equipment on the market. Seller shall bear the cost of such professional engineer and Seller shall secure all studies and upgrades necessitated by or associated with such modification or repower.

Article Three

Seller’s Obligations

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3.08

(d)

Seller acknowledges that nothing in this Section 3.07 excuses Seller from any requirements of the CAISO’s interconnection process or any other applicable interconnection process.

(e)

Seller is solely responsible for all GHG Compliance Costs and all other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating Facility to the extent that such GHG Compliance Costs or other costs result from Seller’s modification or repowering of the Generating Facility in accordance with this Section 3.07.

Metering. (a)

CAISO-Approved Meter. Seller shall, at its own cost, install, maintain and test all CAISO-Approved Meters pursuant to the CAISO Tariff or other applicable metering requirements.

(b)

Check Meter. Buyer may, at its sole cost, furnish and install one Check Meter at the interconnection associated with the Generating Facility at a location designated by Seller or any other location mutually agreeable to the Parties. The Check Meter location must allow for the Check Meter to be interconnected with Buyer’s communication network to permit: (i)

Periodic, remote collection of revenue quality meter data; and

(ii)

Back-up real time transmission of operating-quality meter data through the Telemetry System set forth in Section 3.09; provided, however, that the transmission of such meter data through the Telemetry System is permitted by the CAISO.

Buyer shall test and recalibrate the Check Meter at least once every Term Year. The Check Meter will be locked or sealed, and the lock or seal shall be broken only by a Buyer representative. Seller has the right to be present whenever such lock or seal is broken. Buyer shall replace the Check Meter battery at least once every 36 months; provided, however, if the Check Meter battery fails, Buyer shall promptly replace such battery. (c)

Use of Check Meter for Back-Up Purposes. (i)

Buyer shall routinely compare the Check Meter data to the CAISOApproved Meter data.

(ii)

If the deviation between the CAISO-Approved Meter data (after adjusting (1) for all appropriate compensation and correction factors applied, if applicable, by the CAISO to the CAISO-Approved Meter, or (2) for any

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deviation that may result due to the CAISO-Approved Meter and Check Meter being physically situated in different locations) and the Check Meter data for any comparison is greater than 0.3%, Buyer shall provide Notice to Seller of such deviation and the Parties shall mutually arrange for a meter check or recertification of the Check Meter or CAISOApproved Meter, as applicable.

3.09

(iii)

Each Party shall bear its own costs for any meter check or recertification.

(iv)

Testing procedures and standards for the Check Meter will be the same as for a comparable Buyer-owned meter. Seller shall have the right to have representatives present during all such tests.

(v)

The Check Meter is intended to be used (1) for back-up purposes in the event of a failure or other malfunction of the CAISO-Approved Meter, and (2) in the event Seller has not installed the CAISO-Approved Meter, as further described in Section 3.06(b). Data from the Check Meter will only be used to validate the CAISO-Approved Meter data and, in the event of a failure or other malfunction of the CAISO-Approved Meter, or in accordance with and subject to Section 3.06(b), in place of the CAISOApproved Meter until such time that the CAISO-Approved Meter is certified.

Telemetry System. (a)

Seller is responsible for designing, furnishing, installing, maintaining and testing a real time Telemetry System in accordance with the CAISO Tariff provisions applicable to the Generating Facility. Seller has the right to request any exemption from such requirements from the CAISO so long as it is obtained pursuant to the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.09(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not complied with Section 3.09(a) on or before the Term Start Date, Seller will not be in breach of this Agreement if Seller fully complies with Section 3.09(a) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement set forth in Section 3.09(a) by complying with a milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to the requirement set forth in Section 3.09(a), which

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extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request. (c)

3.10

Buyer agrees that, subject to the limitation set forth in Section 3.09(b) and upon the CAISO’s request, pending Seller compliance with Section 3.09(a), Buyer shall provide to the CAISO any telemetry data reasonably requested by the CAISO for operating information purposes.

Provision of Information. (a)

Within 30 days after the Effective Date, Seller shall provide to Buyer (to the extent not already in Buyer’s possession), subject to Section 9.09: (i)

All currently operative agreements with providers of distribution, transmission or interconnection services for the Generating Facility and all amendments thereto;

(ii)

Any currently operative filings at FERC, including any rulings, orders or other pleadings or papers filed by FERC, concerning the qualification of the Generating Facility as a Qualifying Cogeneration Facility;

(iii)

Any Permits reasonably requested by Buyer concerning the Operation or licensing of the Generating Facility, and any applications or filings requesting or pertaining to such Permits;

(iv)

Each of the following engineering documents for the Generating Facility: 1)

Site plan drawings;

2)

Electrical one-line diagrams;

3)

Control and data acquisition details and configuration documents;

4)

Major electrical equipment specifications;

5)

Process flow diagrams;

6)

Piping and instrumentation diagrams;

7)

General arrangement drawings; and

8)

Aerial photographs of the Site, if any; and

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(v)

Instrument specifications, installation instructions, operating manuals, maintenance procedures and wiring diagrams for the CAISO-Approved Meter(s) and the Telemetry System reasonably requested by Buyer.

(b)

If applicable and subject to Section 9.09, as soon as possible, Seller shall provide to Buyer (i) engineering specifications and design drawings for the Telemetry System, and (ii) annual test reports for the CAISO-Approved Meters.

(c)

Subject to Section 9.09 and upon Buyer’s request, Seller shall make commercially reasonable efforts to provide Buyer with all documentation necessary for Buyer to comply with any discovery or data request for information from the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, which commercially reasonable efforts shall, at a minimum, include providing Buyer with all documentation regarding the operational characteristics or past performance of the Generating Facility if such documentation is requested by the CPUC.

3.11

[Intentionally omitted.]

3.12

Fuel Supply. Seller shall supply all fuel required for the Power Product and any testing or demonstration of the Generating Facility.

3.13

Demonstrations. Seller shall comply with any demonstration required for Resource Adequacy Rulings; provided, however, if such demonstrations could interfere with the operations of Seller, Seller shall be entitled to challenge such requirements with the CPUC or other relevant agency. Absent a ruling or other action granting a stay, compliance shall be required pending resolution of the challenge.

3.14

Operation and Record Keeping. Seller shall: (a)

Operate the Generating Facility in accordance with Prudent Electrical Practices;

(b)

Comply with the Forecasting requirements, as set forth in Exhibit I;

(c)

Use reasonable efforts to Operate the Generating Facility so that the Power Product conforms with the Forecast provided in accordance with Exhibit I;

(d)

Pay all CAISO Charges, as set forth in Exhibit J;

(e)

Pay all SDD Adjustments for which Seller is responsible, as set forth in Exhibit K;

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(f)

Comply with the Maintenance Outage scheduling procedures, as set forth in Exhibit E;

(g)

Comply with the Outage Schedule Submittal Requirements, as set forth in Exhibit R;

(h)

Use reasonable efforts to deliver the maximum possible quantity of As-Available Contract Capacity and associated electric energy during an Emergency Condition or a System Emergency;

(i)

Use reasonable efforts to reschedule any outage that occurs during an Emergency Condition or a System Emergency;

(j)

Keep a daily Operating log for the Generating Facility that includes information on availability, outages, circuit breaker trip operations requiring a manual reset, and any significant events related to the Operation of the Generating Facility, including: (i)

Real and reactive power production;

(ii)

Changes in Operating status;

(iii)

Protective apparatus operations; and

(iv)

Any unusual conditions found during inspections;

(k)

Keep all Operating records required of a Qualifying Cogeneration Facility by any applicable CPUC order as well as any additional information that may be required of a Qualifying Cogeneration Facility in order to demonstrate compliance with all applicable California utility industry standards which have been adopted by the CPUC;

(l)

Provide copies of all daily Operating logs and Operating records to Buyer within 20 days of a Notice from Buyer;

(m)

Provide, upon Buyer’s request, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code or any Applicable Law mandating the reporting by investor-owned utilities of expected or experienced outages by facilities under contract to supply electric energy;

(n)

Pay all Scheduling Fees, as set forth in Exhibit G;

(o)

[Intentionally omitted]

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3.15

(p)

Register with the NERC as the Generating Facility’s Generator Owner and Generator Operator if Seller is required to register by the NERC;

(q)

Maintain documentation of all procedures applicable to the testing and maintenance of the Generating Facility protective devices as necessary to comply with the NERC Reliability Standards applicable to protection systems for electric generators if Seller is required to maintain such documentation by the NERC;

(r)

If Buyer is Scheduling Coordinator, then at least 30 days before the Term End Date, or in accordance with Section 7(a) of Exhibit G, or as soon as practicable before the date of an early termination of this Agreement, (i) submit to the CAISO the name of the Scheduling Coordinator that will replace Buyer, and (ii) cause the Scheduling Coordinator that will replace Buyer to submit a letter to the CAISO accepting the designation as Seller’s Scheduling Coordinator; and

(s)

If Buyer is not Scheduling Coordinator: (i)

Cause its Scheduling Coordinator to submit a Self-Schedule of Seller’s Day-Ahead Forecast associated with the Generating Facility through the IFM; Seller shall then submit the quantity associated with the SelfSchedule of Seller’s Day-Ahead Forecast as a Physical Trade to Buyer in the IFM, specifying the generating resource identifier and all other CAISO-required Inter-SC Trade attributes;

(ii)

Cause its Scheduling Coordinator to submit the IFM Day-Ahead Schedule quantity associated with the Generating Facility as an Inter-SC Trade of IFM Load Uplift Obligation to Buyer to be cleared through the Real-Time Market, specifying all CAISO-required Inter-SC Trade attributes; and

(iii)

Make available to Buyer all CAISO settlement data with respect to the Generating Facility required to validate payments made under this Agreement.

Power Product Curtailments at Transmission Provider’s or CAISO’s Request. (a)

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the CAISO, which may be communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when the CAISO orders curtailment and the Scheduling Coordinator implements such curtailment in compliance with the CAISO Tariff or applicable orders to avoid or address a declared System Emergency.

(b)

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the Transmission Provider, which may be

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communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when curtailment of the Power Product is required to comply with:

(c)

3.16

(i)

A CAISO curtailment declared pursuant to Section 3.15(a) or Transmission Provider declared Emergency Condition, subject to the interconnection agreement between Seller and the Transmission Provider; or

(ii)

Transmission Provider’s maintenance requirements, subject to the interconnection agreement between Seller and the Transmission Provider.

Notwithstanding the above, except as may be required in order to respond to any Emergency Condition or System Emergency, Buyer shall, consistent with FERC Order 888 and the interconnection agreement between Seller and the Transmission Provider and with the applicable provisions of the CAISO Tariff: (i)

Use reasonable good faith efforts to coordinate Transmission Provider’s curtailment needs with Seller to the extent it can influence such needs; or

(ii)

Request the Transmission Provider and CAISO limit the curtailment duration.

(d)

If Seller has entered into a QF PGA or PGA with the CAISO, or an interconnection agreement, the terms of the applicable QF PGA or PGA and the applicable interconnection agreement with respect to CAISO or Transmission Provider curtailments, shall govern the rights and obligations of Buyer and Seller to the extent any provision of this Section 3.15 is inconsistent with such applicable QF PGA or PGA, and interconnection agreement.

(e)

In the event Seller interconnects with a Person other than the CAISO, Seller shall adhere to any reliability curtailment order by such Person pursuant to the applicable tariff provisions of such Person.

Report of Lost Output. To the extent the conditions set forth in Sections 3.16(a) through (e) occur, Seller shall prepare and provide to Buyer, by the fifth Business Day following the end of each month during the Term, a lost output report. The lost output report shall identify the date, time, duration, cause and amount by which the Metered Energy was reduced below the Seller’s Energy Forecast due to: (a)

Maintenance Outages;

(b)

Major Overhauls;

(c)

CAISO or Transmission Provider-ordered curtailments;

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3.17

(d)

Force Majeure; or

(e)

Forced Outages.

FERC Qualifying Cogeneration Facility Status. (a)

Subject to Section 9.09, within 30 Business Days following the end of each year, and within 30 Business Days following the Term End Date, Seller shall provide to Buyer: (i)

A completed copy of Buyer’s “QF Efficiency Monitoring Program – Cogeneration Data Reporting Form”, substantially in the form of Exhibit T, with calculations and verifiable supporting data, which demonstrates the compliance of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation with qualifying cogeneration facility operating and efficiency standards set forth in 18 CFR Part 292, Section 292.205 “Criteria for Qualifying Cogeneration Facilities”, for the applicable year; or

(ii)

A copy of a FERC order waiving for the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation the applicable operating and efficiency standards for qualifying cogeneration facilities, as contemplated in 18 CFR Part 292, Section 292.205, “Criteria for Qualifying Cogeneration Facilities”, for the applicable year, if Seller has received such FERC order; provided, that in the event that Seller receives such a FERC order after the time periods set forth above, Seller shall satisfy this requirement by submitting such FERC order to Buyer within 5 Business Days after FERC’s issuance of such FERC order.

(b)

[Intentionally omitted.]

(c)

Seller shall take all necessary steps, including making or supporting timely filings with the FERC in order to maintain, or obtain a FERC waiver of, the Qualifying Cogeneration Facility status of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation throughout the Term; provided, however, that this obligation does not apply to the extent Seller is unable to maintain Qualifying Cogeneration Facility status using commercially reasonable efforts because of (i) a change in PURPA or in regulations of the FERC implementing PURPA occurring after the Effective Date, or (ii) a change in Applicable Laws directly impacting the Qualifying Cogeneration Facility status

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of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation occurring after the Effective Date. The term “commercially reasonable efforts” in this Section 3.17(c) does not require Seller to pay or incur more than $20,000 multiplied by the number of Term Years in the Term. 3.18

3.19

Notice of Cessation or Termination of Service Agreements. Seller shall provide Notice to Buyer within one Business Day if there is a termination of, or cessation of service under, any agreement required in order for the Generating Facility to: (a)

Interconnect with the Transmission Provider’s electric system;

(b)

Transmit and deliver electric energy to the Delivery Point; or

(c)

Own and operate any CAISO-Approved Meter.

Buyer’s Access Rights. (a)

(b)

3.20

Upon providing at least one Business Day advance Notice to Seller, or as set forth in any Applicable Law (whichever is later), Buyer has the right to examine the Site, the Generating Facility and the Operating records, provided that Buyer follows Seller’s safety policies and procedures that Seller has communicated to Buyer, does not interfere with or hinder Seller’s Operations, and agrees to escorted access to the Generating Facility during regular business hours for: (i)

Any purpose reasonably connected with this Agreement;

(ii)

The exercise of any and all rights of Buyer under Applicable Law or its tariff schedules and rules on file with the CPUC; or

(iii)

The inspection and testing of any Check Meter, CAISO-Approved Meter or the Telemetry System.

Seller shall promptly provide Buyer access to all meter data and data acquisition services both in real-time, and at later times, as Buyer may reasonably request. Seller shall promptly inform Buyer of meter quantity changes after becoming aware of, or being informed of, any such changes by the CAISO. Seller shall provide instructions to the CAISO granting authorizations or other documentation sufficient to provide Buyer with access to the CAISO-Approved Meter and to Seller’s settlement data on OMAR.

Seller Financial Information.

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(a)

The Parties shall determine, through consultation and review with their respective independent registered public accounting firms, whether Buyer is required to consolidate Seller’s financial statements with Buyer’s financial statements for financial accounting purposes under Accounting Standards Codification (ASC) 810/Accounting Standards Update 2009-17, “Consolidation of Variable Interest Entities” (ASC 810), or future guidance issued by accounting profession governance bodies or the SEC that affects Buyer accounting treatment for this Agreement (the “Financial Consolidation Requirement”).

(b)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then: (i)

Within 20 days following the end of each year (for each year that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the year. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements. The annual financial statements should include quarter-to-date and yearly information. Buyer shall provide to Seller a checklist before the end of each year listing the items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the information on the checklist. If audited financial statements are prepared for Seller for the year, Seller shall provide such statements to Buyer within five Business Days after those statements are issued.

(ii)

Within 15 days following the end of each fiscal quarter (for each quarter that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the quarterly period. The financial statements should include quarter-to-date and year-to-date information. Buyer shall provide to Seller a checklist before the end of each quarter listing items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with

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true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements. (iii)

(c)

If Seller regularly prepares its financial data in accordance GAAP, the International Financial Reporting Standards (“IFRS”), or any successor to either of the foregoing (“Successor”), the financial information provided to Buyer shall be prepared in accordance with such principles. If Seller is not a SEC registrant and does not regularly prepare its financial data in accordance with GAAP, IFRS or Successor, the information provided to Buyer shall be prepared in a format consistent with Seller’s regularly applied accounting principles, e.g., the format that Seller uses to provide financial data to its auditor.

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then promptly upon Notice from Buyer, Seller shall allow Buyer’s independent registered public accounting firm such access to Seller’s records and personnel, as reasonably required so that Buyer’s independent registered public accounting firm can conduct financial statement audits in accordance with the standards of the Public Company Accounting Oversight Board (United States), as well as internal control audits in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, as applicable. All expenses for the foregoing shall be borne by Buyer. If Buyer’s independent registered public accounting firm during or as a result of the audits permitted in this Section 3.20(c) determines a material weakness or significant deficiency, as defined by GAAP, IFRS or Successor, as applicable, exists in Seller’s internal controls over financial reporting, then within 90 days of Seller’s receipt of Notice from Buyer, Seller shall remediate any such material weakness or significant deficiency; provided, however, that Seller has the right to challenge the appropriateness of any determination of material weakness or significant deficiency. Seller’s true up to actual activity for yearly or quarterly information as provided herein shall not be evidence of material weakness or significant deficiency.

(d)

Buyer shall treat Seller’s financial statements and other financial information provided under the terms of this Section 3.20 in strict confidence and, accordingly: (i)

Shall utilize such Seller financial information only for purposes of preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, for making regulatory, tax or other filings required by law in which Buyer is required to demonstrate or certify its or any parent company’s financial condition or to obtain credit ratings;

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3.21

(ii)

Shall make such Seller financial information available only to its officers, directors, employees or auditors who are responsible for preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, to the SEC and the Public Company Accounting Oversight Board (United States) in connection with any oversight of Buyer’s or any Buyer parent company financial statement and to those Persons who are entitled to receive confidential information as identified in Sections 9.09(a)(vi) and 9.09(a)(vii); and

(iii)

Buyer shall ensure that its internal auditors and independent registered public accounting firm (1) treat as confidential any information disclosed to them by Buyer pursuant to this Section 3.20, (2) use such information solely for purposes of conducting the audits described in this Section 3.20, and (3) disclose any information received only to personnel responsible for conducting the audits.

(e)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then, within two Business Days following the occurrence of any event affecting Seller which Seller understands, during the Term, would require Buyer to disclose such event in a Form 8-K filing with the SEC, Seller shall provide to Buyer a Notice describing such event in sufficient detail to permit Buyer to make a Form 8-K filing.

(f)

If, after consultation and review, the Parties do not agree on issues raised by Section 3.20(a), then such dispute shall be subject to review by another independent audit firm not associated with either Party’s respective independent registered public accounting firm, reasonably acceptable to both Parties. This third independent audit firm will render its recommendation on whether consolidation by Buyer is required. Based on this recommendation, Seller and Buyer shall mutually agree on how to resolve the dispute. If Seller fails to provide the data consistent with the mutually agreed upon resolution, Buyer may declare an Event of Default pursuant to Section 6.01. If Buyer’s independent audit firm, after the review by the third independent audit firm still determines that Buyer must consolidate, then Seller shall provide the financial information necessary to permit consolidation to Buyer; provided, however, that in addition to the protections in Section 3.20(d), such information shall be password protected and available only to those specific officers, directors, employees and auditors who are preparing and certifying the consolidated financial statements and not for any other purpose.

NERC Electric System Reliability Standards. During the Term, for purposes of complying with any NERC Reliability Standards applicable to the Generating Facility, Seller (or an agent of Seller as agreed to by Buyer in its reasonable discretion) must, if required by the NERC, register with the NERC as the Generator Operator and the

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Generator Owner for the Generating Facility and must perform all Generator Operator Obligations and Generator Owner Obligations except those Generator Operator Obligations that Buyer, in its capacity as Scheduling Coordinator (if Seller has elected to have Buyer serve as its Scheduling Coordinator), is required to perform under this Agreement or under the CAISO Tariff. Notwithstanding anything to the contrary set forth in this Section 3.21 and subject to the indemnity obligations set forth in Section 9.03(h), each Party acknowledges that such Party’s performance of the Generator Operator Obligations or Generator Owner Obligations may not satisfy the requirements for self-certification or compliance with the NERC Reliability Standards, and that it shall be the sole responsibility of each Party to implement the processes and procedures required by the NERC, the WECC, the CAISO, or a Governmental Authority in order to comply with the NERC Reliability Standards. If Buyer is Seller’s Scheduling Coordinator, Buyer as Scheduling Coordinator will reasonably cooperate with Seller to the extent necessary to enable Seller to comply and for Seller to demonstrate Seller’s compliance with the NERC Reliability Standards referenced above. Buyer’s cooperation will include providing to Seller, or such other Person as Seller designates in writing, information in Buyer’s possession that Buyer as Scheduling Coordinator has provided to the CAISO related to the Generating Facility or actions that Buyer has taken as Scheduling Coordinator related to Seller’s compliance with the NERC Reliability Standards referenced above (e.g., Seller’s notices and updates provided by Buyer to the CAISO via SLIC). Buyer may, in its reasonable discretion (depending upon the quantity of information requested by Seller and the timeframe established by Seller for compliance), comply with the requirement to provide information set forth in the previous sentence, by making such information available for inspection by Seller or by providing responsive summaries or excerpts of same, so long as the foregoing enables Seller to comply with the NERC Reliability Standards. In addition, Buyer may redact any information or data that is confidential to Buyer from materials or information to be supplied to Seller. 3.22

Allocation of Availability Incentive Payments and Non-Availability Charges. (a)

If Buyer is the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of Buyer and for Buyer’s account and any Non-Availability Charges will be the responsibility of Buyer and for Buyer’s account.

(b)

If Buyer is not the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of

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Seller and for Seller’s account and any Non-Availability Charges will be the responsibility of Seller and for Seller’s account. 3.23

Seller’s Reporting Requirements. (a)

Seller shall comply with the reporting requirements set forth in Section 3 of Exhibit S.

(b)

Seller shall deliver to Buyer, on or before the 10th Business Day following receipt of a Notice from Buyer, such information that Buyer is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Buyer otherwise requires in order to comply with the Settlement Agreement. *** End of Article Three ***

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ARTICLE FOUR.

BUYER’S OBLIGATIONS

4.01

Obligation to Pay. For Seller’s full compensation under this Agreement, during the Term, Buyer shall make a monthly payment (a “Monthly Contract Payment”) calculated in accordance with Exhibit D.

4.02

Payment Adjustments. (a)

Buyer shall adjust each Monthly Contract Payment to Seller to account for: (i)

Scheduling Fees owed by Seller to Buyer, as set forth in Exhibit G;

(ii)

Any SDD Adjustment, as set forth in Exhibit K;

(iii)

Any Forecast penalties owed by Seller to Buyer, as set forth in Exhibit I;

(iv)

Any CAISO Charges owed by Seller to Buyer, as set forth in Exhibit J;

(v)

Any Physical Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit L;

(vi)

Any SC Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit M;

(vii)

Any payment adjustments (including adjustments to CAISO Charges) provided for under this Agreement;

(viii) Any Governmental Charges owed by either Party to the other Party, as set forth in Section 8.02;

(b)

(ix)

The agreement of the Parties that Buyer shall have no liability to make any energy payments to Seller for any electricity deliveries from the Generating Facility in a Term Year that exceed 120% of Expected Term Year Energy Production; and

(x)

Any payment adjustments provided for to determine Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges, as set forth in Exhibit S.

Unless otherwise required in Exhibit S, during the Term, any payment adjustments will be added to or deducted from a subsequent regular Monthly Contract Payment that is made by Buyer to Seller after the expiration of a 30-day

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period which begins upon Buyer’s receipt of all of the information required in order to calculate payment adjustments. (c)

4.03

Unless otherwise required in Exhibit S, after the Term End Date, Buyer shall invoice Seller for all payment adjustments within 60 days of Buyer’s receipt of all of the information required in order to calculate payment adjustments.

Payment Statement and Payment. (a)

No later than 30 days after the end of each calendar month (or the last day of the month if the month in which the payment statement is being sent is February), or the last Business Day of the month if such 30th day (or 28th or 29th day for February) is not a Business Day, Buyer shall mail to Seller: (i)

A table showing the hourly electric energy quantities for each of the following, in MWh per hour:

1)

Seller’s Energy Forecast;

2)

Seller’s Day-Ahead Forecast;

3)

Metered Energy;

4)

Metered Amounts;

5)

The final Buyer Energy Schedule; and

6)

The final Buyer Parent Energy Schedule.

(ii)

A statement showing:

1)

TOD Period subtotals and overall monthly totals for each of the items set forth in Section 4.03(a)(i);

2)

A calculation of the Monthly Contract Payment, as set forth in Exhibit D;

3)

A calculation of any payment adjustments pursuant to Section 4.02;

4)

A calculation of any payment adjustments pursuant to Exhibit S; and

5)

A calculation of the net dollar amount due for the month.

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(iii)

(b)

Buyer’s payment to Seller, in accordance with Section 9.15, in the net dollar amount owed to Seller for the month (less any overpayments by Buyer of Seller’s GHG Compliance Costs or GHG Charges under Section 4.04 in any calendar month); provided, however, in the event the statement shows a net amount owed to Buyer, Seller shall pay such amount within 20 days of the statement date or, if Seller fails to make such payment, Buyer may offset this amount from a subsequent Monthly Contract Payment.

If Buyer determines that a calculation of Metered Energy or Metered Amounts is incorrect as a result of an inaccurate meter reading or the correction of data by the CAISO in the CAISO’s meter-data acquisition and processing system, Buyer shall promptly recompute the Metered Energy or Metered Amounts quantity for the period of the inaccuracy based on an adjustment of such inaccurate meter reading in accordance with the CAISO Tariff. Buyer shall then promptly recompute any payment or payment adjustment affected by such inaccuracy. Any amount due from Buyer to Seller or Seller to Buyer, as the case may be, shall be made as an adjustment to the next monthly statement that is calculated after Buyer’s recomputation using corrected measurements. If the recomputation results in a net amount owed to Buyer after offsetting any amounts owing to Seller as shown on the next monthly statement, any such additional amount still owing to Buyer shall be shown as an adjustment on Seller’s monthly statement until such amount is fully collected by Buyer. At Buyer’s sole discretion, Buyer may offset any remaining amount owed to Buyer in any subsequent monthly payments to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice.

(c)

(d)

Buyer reserves the right to deduct amounts that would otherwise be due to Seller under this Agreement from any amounts owing and unpaid by Seller to Buyer: (i)

Under this Agreement; or

(ii)

Arising out of or related to any other agreement, tariff, obligation or liability pertaining to the Generating Facility.

Except as provided in Section 4.03(b) and as otherwise provided in this Section 4.03(d), if, within 45 days of receipt of Buyer’s payment statement, Seller does not give Notice to Buyer of an error, then Seller shall be deemed to have waived any error in Buyer’s statement, computation and payment and the statement shall

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Buyer’s Obligations

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

be conclusively deemed correct and complete; provided, however, that if an error is identified by Seller as a result of settlement, audit or other information provided to Seller by the CAISO after the expiration of the original 45-day period, Seller shall have an additional 90 days from the date on which it receives the information from the CAISO in which to give Notice to Buyer of the error identified by such settlement, audit or other information. If Seller identifies an error in Seller’s favor and Buyer agrees that the identified error occurred, Buyer shall reimburse Seller for the amount of the underpayment caused by the error and add the underpayment to the next monthly statement that is calculated. If Seller identifies an error in Buyer’s favor and Buyer agrees that the identified error occurred, Seller shall reimburse Buyer for the amount of overpayment caused by the error and Buyer shall apply the overpayment to the next monthly statement that is calculated. If the recomputation results in a net amount still owing to Buyer after applying the overpayment, the next monthly statement shall show a net amount owing to Buyer. At Buyer’s sole discretion, Buyer may apply this net amount owing to Buyer in any subsequent monthly statements to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice. The Parties shall negotiate to resolve any disputes regarding claimed errors in a statement. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. Nothing in this Section 4.03 limits a Party’s rights under applicable tariffs, other agreements or Applicable Law.

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Buyer’s Obligations

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

4.04

GHG Compliance Costs. Buyer shall pay for Seller’s GHG Compliance Costs and GHG Charges in accordance with Exhibit S; provided, however, that notwithstanding anything to the contrary set forth in this Agreement (including Exhibit S), in no event will Buyer pay for any of Seller’s GHG Compliance Costs or GHG Charges to the extent that such GHG Compliance Costs or GHG Charges are associated with deliveries of the Power Product that are in excess of 120% of the Expected Term Year Net Energy Production in any Term Year.

4.05

No Representation by Buyer. Any review by Buyer of the design, engineering, construction, testing and Operation of the Generating Facility is solely for Buyer’s information. Buyer makes no representation that: (a)

It has reviewed the financial viability, technical feasibility, operational capability, or long term reliability of the Generating Facility;

(b)

The Generating Facility complies with any Applicable Laws; or

(c)

The Generating Facility will be able to meet the terms of this Agreement.

Seller shall in no way represent to any third party that any such review by Buyer constitutes any such representation. 4.06

Buyer’s Responsibility. Buyer shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable transmission and delivery of electric energy at and after the Delivery Point.

4.07

Buyer’s Reporting Requirements. Buyer shall deliver to Seller, on or before the 10th Business Day following receipt of a Notice from Seller, such information as Seller is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Seller otherwise requires in order to comply with the Settlement Agreement. *** End of Article Four ***

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Buyer’s Obligations

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE FIVE.

FORCE MAJEURE

5.01

No Default for Force Majeure. Neither Party will be in default in the performance of any of its obligations set forth in this Agreement, except for obligations to pay money, when and to the extent failure of performance is caused by Force Majeure.

5.02

Requirements Applicable to the Claiming Party. If a Party, because of Force Majeure, is rendered wholly or partly unable to perform its obligations when due under this Agreement, such Party (the “Claiming Party”) shall be excused from whatever performance is affected by the Force Majeure to the extent so affected. In order to be excused from its performance obligations under this Agreement by reason of Force Majeure: (a)

The Claiming Party, within 14 days after the initial occurrence of the claimed Force Majeure, must give the other Party Notice describing the particulars of the occurrence; and

(b)

The Claiming Party must provide timely evidence reasonably sufficient to establish that the occurrence constitutes Force Majeure as defined in this Agreement.

The suspension of the Claiming Party’s performance due to Force Majeure may not be greater in scope or longer in duration than is required by such Force Majeure. In addition, the Claiming Party shall use diligent efforts to remedy its inability to perform. This Article Five will not require the settlement of any strike, walkout, lockout or other labor dispute on terms which, in the sole judgment of the Claiming Party, are contrary to its interest. It is understood and agreed that the settlement of strikes, walkouts, lockouts or other labor disputes shall be at the sole discretion of the Claiming Party. When the Claiming Party is able to resume performance of its obligations under this Agreement, the Claiming Party shall give the other Party prompt Notice to that effect. 5.03

Termination. Either Party may terminate this Agreement on Notice, which Notice will be effective five Business Days after such Notice is provided, in the event of Force Majeure which materially interferes with such Party’s ability to perform its obligations under this Agreement and which extends for more than 365 consecutive days, or for more than a total of 365 days in any consecutive 540-day period. *** End of Article Five ***

Article Five

Force Majeure

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE SIX. 6.01

EVENTS OF DEFAULT; REMEDIES

Events of Default. An “Event of Default” means the occurrence of any of the following : (a)

With respect to either Party (a “Defaulting Party”): (i)

Any representation or warranty made by such Party in this Agreement is false or misleading in any material respect when made or when deemed made or repeated if the representation or warranty is continuing in nature, if such misrepresentation or breach of warranty is not: 1)

Remedied within 10 Business Days after Notice from the NonDefaulting Party to the Defaulting Party; or

2)

Capable of a cure, but the Non-Defaulting Party’s damages resulting from such misrepresentation or breach of warranty can reasonably be ascertained and the payment of such damages is not made within 10 Business Days after a Notice of such damages is provided by the Non-Defaulting Party to the Defaulting Party;

(ii)

Except for an obligation to make payment when due, the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default or to the extent excused by a Force Majeure) if such failure is not remedied within 30 days after Notice of such failure is provided by the Non-Defaulting Party to the Defaulting Party, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 30-day cure period, the Defaulting Party shall have such additional time (not to exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as such Defaulting Party promptly commences and diligently pursues such cure;

(iii)

A Party fails to make when due any payment (other than amounts disputed in accordance with the terms of this Agreement) due and owing under this Agreement and such failure is not cured within five Business Days after Notice is provided by the Non-Defaulting Party to the Defaulting Party of such failure;

(iv)

A Party becomes Bankrupt;

(v)

A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another Person and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee Person fails to assume all the obligations of such

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Events of Default; Remedies

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Party under this Agreement to which such Party or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party; (vi)

An event of default occurs (howsoever determined) under any agreement between Buyer and Seller (other than this Agreement but including the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation) and, after giving effect to any applicable notice requirement or cure period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that agreement; or

(vii)

The Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, the Transition EEI Agreement or the Transition Tolling Confirmation or Transition RA Confirmation.

(b)

[Intentionally omitted.]

(c)

With respect to Seller: (i)

Seller does not own or lease the Generating Facility or otherwise have the authority over the Generating Facility as required in Section 3.03, and Seller has not cured a failure with respect to Section 3.03 within 30 days after providing Notice to Buyer in accordance with Section 3.03;

(ii)

If Seller abandons the Generating Facility (for purposes of this Section 6.01(c)(ii), Seller will be deemed to have abandoned the Generating Facility if Seller has ceased work on the Generating Facility or the Generating Facility has ceased production and delivery of the Product for a consecutive thirty (30) day period and such cessation is not a result of an event of Force Majeure);

(iii)

During the Term, except as provided for in Section 3.01(d), Seller (1) conveys, transfers, allocates, designates, awards, reports or otherwise provides any and all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except as may relate to transactions in the imbalance market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) starts up or Operates the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws);

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(iv)

Seller intentionally or knowingly delivers, Schedules, or attempts to deliver or Schedule at the Delivery Point for sale under this Agreement electric energy that was not generated by the Generating Facility;

(v)

Seller removes from the Site equipment upon which the Net Contract Capacity has been based, except for the purposes of replacement, refurbishment, repair, repowering or maintenance, and such equipment is not returned within five Business Days after Notice from Buyer to Seller;

(vi)

Subject to Section 3.17(c), the Generating Facility fails to maintain its status as a Qualifying Cogeneration Facility;

(vii)

Termination of, or cessation of service under, any agreement necessary for the interconnection of the Generating Facility to the Transmission Provider’s electric system for transmission and delivery of the electric energy from the Generating Facility to the Delivery Point, or for metering the Metered Energy, and such service is not reinstated, or alternative arrangements implemented, within 120 days after such termination or cessation;

(viii) Seller fails to make all reasonable efforts to increase the Power Output from the Generating Facility to the Firm Contract Capacity during an Emergency Condition or a System Emergency; (ix)

Seller fails to provide any financial statements or other information within the timeframe and in the manner set forth in Sections 3.20(b)(i) and (ii), and such failure is not remedied within 10 days after Notice from Buyer to Seller;

(x)

Seller fails to remediate any material weakness or significant deficiency in internal controls over financial reporting in accordance with Section 3.20(c), and such failure is not remedied within 90 days after Notice from Buyer to Seller;

(xi)

Seller fails to take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term as specified in Section 3.01, if such failure is not remedied within 10 days after Notice of such failure is provided by Buyer to Seller, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 10-day cure period, Seller shall have such additional time (not to exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as Seller promptly commences and diligently pursues such cure;

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Events of Default; Remedies

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(xii)

[Intentionally omitted]

(xiii) If any failure by Seller to comply with the CAISO Tariff materially impacts Buyer’s ability to comply with this Agreement, the CAISO Tariff or other Applicable Laws, and such failure by Seller (including any consequences suffered by Buyer) is not cured within 30 days after Notice from Buyer to Seller;

6.02

6.03

(xiv)

If Seller materially modifies or repowers the Generating Facility (except as provided in Section 3.07(c)) without Buyer’s prior written consent; or

(xv)

If Seller fails to satisfy all of the conditions set forth in Section 2.01 before the Term Start Date, and such failure is not cured within 30 Business Days after Notice from Buyer to Seller.

Early Termination. If an Event of Default has occurred, there will be no opportunity for cure except as specified in Section 6.01 or pursuant to a Collateral Assignment Agreement agreed upon by Buyer, Seller and Lender in accordance with Section 9.05. The Party taking the default (the “Non-Defaulting Party”) will have the right to: (a)

Designate by Notice to the Defaulting Party a date, no later than 20 days after the Notice is effective, for the early termination of this Agreement (an “Early Termination Date”);

(b)

Immediately suspend performance under this Agreement; and

(c)

Pursue all remedies available at law or in equity against the Defaulting Party (including monetary damages), except to the extent that such remedies are limited by the terms of this Agreement.

Termination Payment. As soon as practicable after an Early Termination Date is declared, the Non-Defaulting Party shall provide Notice to the Defaulting Party of the sum of all amounts owed by the Defaulting Party under this Agreement less any amounts owed by the Non-Defaulting Party to the Defaulting Party under this Agreement, including any Forward Settlement Amount (the “Termination Payment”). The Notice shall include a written statement setting forth, in reasonable detail, the calculation of such Termination Payment, including the Forward Settlement Amount, together with appropriate supporting documentation. If the Termination Payment is positive, the Defaulting Party shall pay such amount to the Non-Defaulting Party within 10 Business Days after the Notice is provided. If the Termination Payment is negative (i.e., the Non-Defaulting Party owes the Defaulting Party more than the Defaulting Party owes the Non-Defaulting Party), then the Non-

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Events of Default; Remedies

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Defaulting Party shall pay such amount to the Defaulting Party within 10 Business Days after the Notice is provided. The Parties shall negotiate to resolve any disputes regarding the calculation of the Termination Payment and Forward Settlement Amount. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. *** End of Article Six ***

Article Six

Events of Default; Remedies

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE SEVEN. LIMITATIONS OF LIABILITIES EXCEPT AS SET FORTH IN THIS ARTICLE SEVEN, THERE ARE NO WARRANTIES BY EITHER PARTY UNDER THIS AGREEMENT, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY IS LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED, UNLESS THE PROVISION IN QUESTION PROVIDES THAT THE EXPRESS REMEDIES ARE IN ADDITION TO OTHER REMEDIES THAT MAY BE AVAILABLE. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, THE OBLIGOR’S LIABILITY IS LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. THE VALUE OF ANY PRODUCTION TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. THE VALUE OF ANY INVESTMENT TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. UNLESS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, INCLUDING THE PROVISIONS OF SECTION 9.03, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS IMPOSED IN THIS ARTICLE SEVEN ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE.

Article Seven

Limitations of Liabilities

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID UNDER THIS AGREEMENT ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED UNDER THIS AGREEMENT CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. NOTHING IN THIS ARTICLE SEVEN PREVENTS, OR IS INTENDED TO PREVENT BUYER FROM PROCEEDING AGAINST OR EXERCISING ITS RIGHTS WITH RESPECT TO ANY SECURED INTEREST IN COLLATERAL. *** End of Article Seven ***

Article Seven

Limitations of Liabilities

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE EIGHT. GOVERNMENTAL CHARGES 8.01

Cooperation to Minimize Tax Liabilities. Each Party shall use diligent efforts to implement the provisions of and to administer this Agreement in accordance with the intent of the Parties to minimize all taxes, so long as neither Party is materially adversely affected by such efforts.

8.02

Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any Governmental Authority (“Governmental Charges”) on or with respect to the Generating Facility, Monthly Contract Payments made by Buyer to Seller, or the Power Product before the Delivery Point, including ad valorem taxes and other taxes attributable to the Generating Facility, the Site or land rights or interests in the Site or the Generating Facility. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Power Product at and after the Delivery Point. If Seller is required by Applicable Laws to remit or pay Governmental Charges which are Buyer’s responsibility under this Agreement, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by Applicable Law or regulation to remit or pay Governmental Charges which are Seller’s responsibility under this Agreement, Buyer may deduct such amounts from payments to Seller made pursuant to Article Four. If Buyer elects not to deduct such amounts from Seller’s payments, Seller shall promptly reimburse Buyer for such amounts upon Notice from Buyer of the amount to be reimbursed. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under Applicable Laws. Nothing stated in this Section 8.02 relieves Buyer of its obligation to pay Seller for Seller’s GHG Compliance Costs and GHG Charges in accordance with and subject to this Agreement (including Exhibit S).

8.03

Providing Information to Taxing Governmental Authorities. To the extent required by Applicable Law and subject to Section 9.09(b), each Party shall provide information concerning the Generating Facility to any requesting taxing Governmental Authority. *** End of Article Eight ***

Article Eight

Governmental Charges

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

ARTICLE NINE. 9.01

MISCELLANEOUS

Representations, Warranties and Covenants. (a)

On the Effective Date, each Party represents and warrants to the other Party that: (i)

It is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;

(ii)

The execution, delivery and performance of this Agreement are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any Applicable Laws;

(iii)

This Agreement constitutes a legally valid and binding obligation enforceable against it in accordance with its terms, subject to any Equitable Defenses;

(iv)

There is not pending, or to its knowledge, threatened against it or, in the case of Seller, any of its Related Entities, any legal proceeding that could materially adversely affect its ability to perform under this Agreement;

(v)

No Event of Default with respect to it has occurred and is continuing and no such event or circumstance will occur as a result of its entering into or performing its obligations under this Agreement;

(vi)

It is acting for its own account, and its decision to enter into this Agreement is based upon its own judgment, not in reliance upon the advice or recommendations of the other Party and it is capable of assessing the merits of and understanding, and understands and accepts the terms, conditions and risks of this Agreement;

(vii)

It has not relied on any promises, representations, statements or information of any kind whatsoever that are not contained in this Agreement in deciding to enter into this Agreement; and

(viii) It has entered into this Agreement in connection with the conduct of its business and it has the capacity or ability to provide or receive the Power Product as contemplated by this Agreement. (b)

On the Effective Date, each Party covenants to the other Party that, except for CPUC Approval in the case of Buyer, and for certain authorizations that Seller

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Miscellaneous

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

will need to obtain from FERC, it has or will timely acquire all regulatory authorizations necessary for it to legally perform its obligations under this Agreement. (c) 9.02

9.03

On the Effective Date, Seller represents and warrants to Buyer that the Generating Facility is an Existing Qualifying Cogeneration Facility.

Additional Covenants by Seller. Seller covenants to Buyer that: (a)

It will have Site Control as of the earlier of (i) the Term Start Date and (ii) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term;

(b)

Throughout the Term, it or its subcontractors will own or lease and Operate the Generating Facility unless otherwise agreed to by the Parties;

(c)

Throughout the Term, it will deliver the Product to Buyer free and clear of all liens, security interests, Claims and encumbrances or any interest therein or thereto by any Person;

(d)

Throughout the Term, it will hold the rights to all of the Product, subject to the terms of this Agreement;

(e)

From the Effective Date until the Term End Date, the Generating Facility will maintain its status as a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(f)

Throughout the Term, it will not (1) convey, transfer, allocate, designate, award, report or otherwise provide any or all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except, if Buyer is not Scheduling Coordinator, as may relate to transactions in the Real-Time Market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) start-up or Operate the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws); and

(g)

Seller shall comply with all (i) applicable cap-and-trade programs for the regulation of Greenhouse Gas, as established by any Governmental Authority pursuant to federal or state legislation, and (ii) other applicable programs regulating Greenhouse Gas emissions.

Indemnity.

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Miscellaneous

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(a)

Each Party as indemnitor shall defend, save harmless and indemnify the other Party and the directors, officers, employees, and agents of such other Party against and from any and all loss, liability, damage, claim, cost, charge, demand, or expense (including any direct, indirect, or consequential loss, liability, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees) for injury or death to Persons, including employees of either Party, and physical damage to property including property of either Party arising out of or in connection with the negligence or willful misconduct of the indemnitor relating to its obligations under this Agreement. This indemnity applies notwithstanding the active or passive negligence of the indemnitee. However, neither Party is indemnified under this Agreement for its loss, liability, damage, claim, cost, charge, demand or expense to the extent resulting from its negligence or willful misconduct.

(b)

Each Party releases and shall defend, save harmless and indemnify the other Party from any and all loss, liability, damage, claim, cost, charge, demand or expense arising out of or in connection with any breach made by the indemnifying Party of its representations, warranties and covenants in Section 9.01 and Section 9.02.

(c)

The provisions of this Section 9.03 may not be construed to relieve any insurer of its obligations to pay any insurance Claims in accordance with the provisions of any valid insurance policy.

(d)

Notwithstanding anything to the contrary in this Agreement, if Seller fails to comply with the provisions of Section 9.10, Seller shall, at its own cost, defend, save harmless and indemnify Buyer, its directors, officers, employees, and agents, assigns, and successors in interest, from and against any and all loss, liability, damage, claim, cost, charge, demand, or expense of any kind or nature (including any direct, indirect, or consequential loss, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees and other costs of litigation), resulting from injury or death to any person or damage to any property, including the personnel or property of Buyer, to the extent that Buyer would have been protected had Seller complied with all of the provisions of Section 9.10. The inclusion of this Section 9.03(d) is not intended to create any express or implied right in Seller to elect not to provide the insurance required under Section 9.10.

(e)

Each Party shall defend, save harmless and indemnify the other Party against any Governmental Charges for which such indemnifying Party is responsible under Article Eight.

Article Nine

Miscellaneous

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

9.04

(f)

Seller shall defend, save harmless and indemnify Buyer against any increase in GHG Compliance Costs and other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating Facility to the extent that such GHG Compliance Costs or other costs result from Seller’s modification or repowering of the Generating Facility in accordance with Section 3.07.

(g)

Seller shall defend, save harmless and indemnify Buyer against any penalty imposed upon Buyer as a result of Seller’s failure to fulfill its obligations regarding Resource Adequacy Benefits as set forth in Sections 3.01 and 3.02, with the exception of the obligations set forth in Section 3.01(c)(vi).

(h)

Seller is solely responsible for any NERC Standards Non-Compliance Penalties arising from or relating to Seller’s failure to perform the Generator Operator Obligations or the Generator Owner Obligations for which Seller is responsible, in accordance with Section 3.21, and will indemnify, defend and hold Buyer harmless from and against all liabilities, damages, Claims, losses, and reasonable costs and expenses (which shall include reasonable costs and expenses of outside or in-house counsel) incurred by Buyer arising from or relating to Seller’s actions or inactions that result in NERC Standards Non-Compliance Penalties or an attempt by any Governmental Authority, Person to assess such NERC Standards Non-Compliance Penalties against Buyer. Buyer will indemnify, defend and hold Seller harmless from and against all liabilities, damages, Claims, losses and reasonable costs and expenses (which shall include reasonable costs of outside and in-house counsel) incurred by Seller for any NERC Standards NonCompliance Penalties to the extent they are due to Buyer’s negligence or willful misconduct in performing its role as Seller’s Scheduling Coordinator during the Term.

(i)

All indemnity rights will survive the termination of this Agreement for 12 months.

Assignment. (a)

With Consent. Subject to Section 9.04(b), Seller may not transfer or assign this Agreement or its rights under this Agreement without the prior written consent of Buyer, which consent may not be unreasonably withheld or delayed. Any direct or indirect change of control of Seller (whether voluntary or by operation of law) will be deemed an assignment and will require the prior written consent of Buyer, which consent will not be unreasonably withheld. For purposes of this Section 9.04, Buyer will not withhold its consent to an indirect change of control of Seller if Seller demonstrates to Buyer’s reasonable satisfaction that Seller shall continue to perform its obligations under this Agreement as if no such indirect change of control had occurred.

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(b)

9.05

Without Consent. Notwithstanding anything to the contrary set forth in Section 9.04(a): (i)

Seller may, without the consent of Buyer (and without relieving itself from liability hereunder): (1) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements in accordance with Section 9.05; or (2) transfer or assign this Agreement to a Related Entity of Seller, which Related Entity’s creditworthiness is equal to or higher than that of Seller; and

(ii)

Seller does not need to obtain Buyer’s consent to any change of control described in this Section 9.04 if such change of control results from a purchase of the outstanding shares of a publicly traded company.

Consent to Collateral Assignment. Subject to the provisions of this Section 9.05, Seller may (but is not obligated to) assign this Agreement as collateral to a Lender for any financing or refinancing of the Generating Facility, including a Sale-Leaseback Transaction or Equity Investment and, in connection therewith, Buyer shall in good faith work with Seller and Lender to agree upon a consent to a collateral assignment of this Agreement or to a Sale-Leaseback Transaction or Equity Investment, as applicable (“Collateral Assignment Agreement”). The Collateral Assignment Agreement shall be in form and substance reasonably agreed to by Buyer, Seller and Lender, and shall include, among others, the following provisions (together with such other commercially reasonable provisions required by any Lender that are reasonably acceptable to Buyer): (a)

Buyer shall give, to the Person(s) to be specified by Lender in the Collateral Assignment Agreement, simultaneously with the Notice to Seller and before exercising its right to terminate this Agreement, written Notice of any event or circumstance known to Buyer which would, if not cured within the applicable cure period specified in Article VI, constitute an Event of Default (an “Incipient Event of Default”);

(b)

Lender shall have the right to cure an Incipient Event of Default or an Event of Default by Seller in accordance with the same provisions of this Agreement as apply to Seller;

(c)

Following an Event of Default by Seller under this Agreement, Buyer may require Seller to (although Lender may, but shall have no obligation, subject to 9.05(g)) provide to Buyer a report concerning:

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(i)

The status of efforts by Seller or Lender to develop a plan to cure the Event of Default;

(ii)

Impediments to the cure plan or its development;

(iii)

If a cure plan has been adopted, the status of the cure plan’s implementation (including any modifications to the plan as well as the expected timeframe within which any cure is expected to be implemented); and

(iv)

Any other information which Buyer may reasonably require related to the development, implementation and timetable of the cure plan;

(d)

Seller or Lender shall provide the report to Buyer within 10 Business Days after Notice from Buyer requesting the report. Buyer shall have no further right to require the report with respect to a particular Event of Default after that Event of Default has been cured;

(e)

Lender shall have the right to cure an Event of Default or Incipient Event of Default on behalf of Seller, only if Lender sends a written notice to Buyer before the end of any cure period indicating Lender’s intention to cure. Lender may remedy or cure the Event of Default or Incipient Event of Default within the cure period under this Agreement. Such cure period for Lender shall be extended for each day Buyer does not provide the Notice to Lender referred to in Section 9.05(a). In addition, such cure period may, in Buyer’s reasonable discretion, be extended by no more than an additional 180 days. If possession of the Generating Facility is necessary to cure such Incipient Event of Default or Event of Default, Lender has commenced foreclosure proceedings within 60 days after receipt of such Notice from Buyer, and Lender is making diligent and consistent efforts to complete such foreclosure, take possession of the Generating Facility and promptly cure the Incipient Event of Default or Event of Default, Lender or its designee(s) or assignee(s) will be allowed a reasonable period of time to complete such foreclosure proceedings, take possession of the Generating Facility and cure such Incipient Event of Default or Event of Default, not to exceed 180 days after Lender’s commencement of foreclosure. Additionally, if Lender is prohibited from curing any Incipient Event of Default or Event of Default by any process, stay or injunction issued by a Governmental Authority or pursuant to any bankruptcy, insolvency or similar proceedings, then the time period for curing such Incipient Event of Default or Event of Default shall be extended for the period of the prohibition provided that Lender is exercising reasonable diligence in having such process, stay or injunction removed;

(f)

Lender shall have the right to consent before any termination of this Agreement which does not arise out of an Event of Default or the end of the Term;

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(g)

Lender shall receive prior Notice of, and shall have the right to approve material amendments to this Agreement, which approval may not be unreasonably withheld, delayed or conditioned;

(h)

In the event Lender, directly or indirectly, takes title to the Generating Facility (including title by foreclosure or deed in lieu of foreclosure), the Person taking title to the Generating Facility shall assume all of Seller’s obligations arising under this Agreement and all related agreements (subject to such limits on liability as are mutually agreed to by Seller, Buyer and Lender as set forth in the Collateral Assignment Agreement); provided, however, that Lender (or such Person) shall have no liability for any monetary obligations of Seller under this Agreement which are due and owing to Buyer as of the assumption date (but this provision may not be interpreted to limit Buyer’s rights to proceed against Seller as a result of an Event of Default) and Lender’s (or such Person’s) liability to Buyer after such assumption shall be limited to its interest in the Generating Facility; provided further, that before such assumption, if Buyer advises Lender (or such Person) that Buyer will require that Lender (or such Person) cure (or cause to be cured) one or more monetary or non-monetary Incipient Event(s) of Default or Event(s) of Default existing as of the date such Person takes title in order to avoid the exercise by Buyer (in its sole discretion) of Buyer’s right to terminate this Agreement with respect to such Incipient Event(s) of Default or Event(s) of Default, then Lender (or such Person) at its option and in its sole discretion may elect to either (i) cause such Incipient Event(s) of Default or Event of Default to be cured, or (ii) not assume this Agreement;

(i)

If Lender has assumed this Agreement as provided in Section 9.05(h) and elects to sell or transfer the Generating Facility (after Lender directly or indirectly, takes title to the Generating Facility), or sale of the Generating Facility occurs through the actions of Lender or an agent of or representative of Lender (excluding any foreclosure sale where a third party other than Lender, Seller, an Related Entity of Lender or an Related Entity of Seller is the buyer), then Lender must cause the transferee or buyer to assume all of Seller’s obligations arising under this Agreement and all related agreements as a condition of the sale or transfer excluding, however, a foreclosure (unless the transferee or buyer is Lender, Seller, an Related Entity of Lender or an Related Entity of Seller). Lender shall be released from all further obligations under the Agreement and all related documents following such assumption. Such sale or transfer (excluding a foreclosure) may be made only to a Person reasonably acceptable to Buyer; and

(j)

If this Agreement is rejected in Seller’s Bankruptcy or otherwise terminated in connection therewith and if Lender or its representative or designee, directly or indirectly, takes title to the Generating Facility, then, at the request of either Buyer or Lender, Buyer and Lender (or its designee or representative) shall promptly enter into a new agreement with Buyer having substantially the same

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terms as this Agreement for the term that would have been remaining under this Agreement, provided that Lender’s (or its designee’s or representative’s) liability under such new agreement shall be limited to its interest in the Generating Facility and neither Lender (or its designee or representative) nor Buyer shall have any personal liability to the other for any amounts owing and neither Buyer nor Lender (or its designee or representative) shall have any obligation to cure any defaults under the original Agreement that was rejected in, or otherwise terminated in connection with Seller’s Bankruptcy. 9.06

Governing Law and Jury Trial Waiver. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER ARE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. TO THE EXTENT ENFORCEABLE AT SUCH TIME, EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT.

9.07

Notices. All Notices shall be provided as specified in Exhibit N. Notices (other than Forecasts and Scheduling requests) shall, unless otherwise specified in this Agreement, be in writing and may be delivered by hand delivery, first class United States mail, overnight courier service, electronic transmission or facsimile. Notices provided in accordance with this Section 9.07 are deemed given as follows: (a)

Notice by facsimile, electronic transmission or hand delivery is deemed given at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise are deemed given at the close of business on the next Business Day;

(b)

Notice by overnight first class United States mail or overnight courier service is deemed given on the next Business Day after such Notice is sent out;

(c)

Notice by first class United States mail is deemed given two Business Days after the postmarked date;

(d)

Notices are effective on the date deemed given, unless a different date for the Notice to go into effect is stated in another section of this Agreement;

(e)

A Party may change its designated representatives, addresses and other contact information by providing Notice of same in accordance herewith; and

(f)

All Notices for this Generating Facility must reference the identification number set forth on the cover page of this Agreement.

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9.08

General. (a)

This Agreement supersedes all prior agreements, whether written or oral, between the Parties with respect to its subject matter and constitutes the entire agreement between the Parties relating to its subject matter.

(b)

This Agreement will not be construed against any Party as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof.

(c)

Except to the extent provided for in this Agreement, no amendment or modification to this Agreement is enforceable unless reduced to a writing signed by all Parties.

(d)

If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement will remain in full force and effect. Any provision of this Agreement held invalid or unenforceable only in part or degree will remain in full force and effect to the extent not held invalid or unenforceable.

(e)

Waiver by a Party of any default by the other Party will not be construed as a waiver of any other default.

(f)

The term “including” when used in this Agreement is by way of example only and will not be considered in any way to be in limitation.

(g)

The word “or” when used in this Agreement includes the meaning “and/or” unless the context unambiguously dictates otherwise.

(h)

The headings used in this Agreement are for convenience and reference purposes only and will not affect its construction or interpretation. All references to “Articles”, “Sections” and “Exhibits” refer to the corresponding Articles, Sections and Exhibits of this Agreement. Unless otherwise specified, all references to “Articles” or “Sections” in Exhibits A through T refer to the corresponding Articles and Sections in the main body of this Agreement. Words having wellknown technical or industry meanings have such meanings unless otherwise specifically defined in this Agreement.

(i)

Where days are not specifically designated as Business Days, they are calendar days. Where years are not specifically designated as Term Years, they are calendar years.

(j)

This Agreement will apply to, be binding in all respects upon and inure to the benefit of the successors and permitted assigns of the Parties. Nothing in this

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Agreement will be construed to give any Person other than the Parties any legal or equitable right, remedy or claim under or with respect to this Agreement or any provision of this Agreement, except as shall inure to a successor or permitted assignee.

9.09

(k)

No provision of this Agreement is intended to contradict or supersede any applicable agreement between the Parties or between or among Seller, the CAISO and the Transmission Provider, covering transmission, distribution, metering, scheduling or interconnection of electric energy (including the PGA and QF PGA). In the event of an apparent contradiction between this Agreement and any such agreement, the applicable agreement controls.

(l)

Whenever this Agreement specifically refers to any law, tariff, government department or agency, regional reliability council, Transmission Provider, or credit rating agency, the Parties agree that the reference also refers to any successor to such law, tariff or organization.

(m)

The Parties acknowledge and agree that this Agreement and the transactions contemplated by this Agreement constitute a “forward contract” within the meaning of the United States Bankruptcy Code and that Buyer and Seller are each “forward contract merchants” within the meaning of the United States Bankruptcy Code.

(n)

This Agreement may be executed in one or more counterparts, each of which will be deemed to be an original of this Agreement and all of which, when taken together, will be deemed to constitute one and the same agreement. The exchange of copies of this Agreement and of signature pages by facsimile transmission, an Adobe Acrobat file or by other electronic means constitutes effective execution and delivery of this Agreement as to the Parties and may be used in lieu of the original Agreement for all purposes. Signatures of the Parties transmitted by facsimile or by other electronic means will be deemed to be their original signatures for all purposes.

(o)

The Parties acknowledge that neither Party is waiving any right it may have under the Settlement Agreement.

Confidentiality. (a)

Neither Party may disclose any Confidential Information to a third party, other than: (i)

To such Party’s employees, Lenders, investors, attorneys, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential;

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(ii)

To potential Lenders with the consent of Buyer, which consent will not be unreasonably withheld; provided, however, that disclosure (1) of cash flow and other financial projections to any potential Lender or investor in connection with a potential loan or tax equity investment; or (2) to potential Lenders or investors with whom Seller has negotiated (but not necessarily executed) a term sheet or other similar written mutual understanding, will not require such consent of Buyer; provided further, that in each case such potential Lender or investor has a need to know such information and has agreed to keep such terms confidential;

(iii)

To Buyer’s Procurement Review Group, as defined in D.02-08071, or Buyer’s Cost Allocation Mechanism Group, as defined in D.06-07-029 and D.08-09-012, and pursuant to the Settlement Agreement and related Decisions, subject to a protective order applicable to Buyer’s Procurement Review Group or Buyer’s Cost Allocation Mechanism Group;

(iv)

With respect to Confidential Information other than nonpublic financial information of Seller supplied to Buyer pursuant to Section 3.20, to the CPUC, the CEC or the FERC, under seal for any regulatory purpose, including policymaking, but only provided that the confidentiality protections from the CPUC under Section 583 of the California Public Utilities Code or other statute, order or rule offering comparable confidentiality protection are in place before the communication of such Confidential Information;

(v)

In order to comply with any Applicable Law or any exchange, Control Area or CAISO rule, or order issued by a court or entity with competent jurisdiction over the disclosing party, other than to those entities set forth in Section 9.09(a)(vi);

(vi)

In order to comply with any Applicable Law, including applicable regulation, rule, subpoena, or order of the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, or any discovery or data request of the CPUC;

(vii)

To representatives of a Party’s credit ratings agencies who have a need to review the terms and conditions of this Agreement for the purpose of assisting the Party in evaluating this Agreement for credit rating purposes or with respect to the potential impact of this Agreement on the Party’s financial reporting obligations, in each case subject to confidentiality restrictions no less stringent than as set forth in this Agreement; and

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(viii) As may reasonably be required to participate in WREGIS or other process recognized under Applicable Laws for the registration, transfer or ownership of Green Attributes associated with the Related Products.

9.10

(b)

In connection with requirements, requests or orders to produce documents or information in the circumstances provided in Sections 8.03 and 9.09(a)(vi) (“Disclosure Order”) each Party shall, to the extent practicable, use reasonable efforts to (i) notify the other Party before disclosing the confidential information, and (ii) prevent or limit such disclosure. After using such reasonable efforts, the disclosing party may not be (x) prohibited from complying with a Disclosure Order, or (y) liable to the other Party for monetary or other damages incurred in connection with the disclosure of any terms or conditions of this Agreement which are the subject of such Disclosure Order.

(c)

Except as provided in clause (y) of Section 9.09(b), the Parties are entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, the confidentiality obligations set forth in this Section 9.09.

Insurance. (a)

As of the Effective Date and throughout the Term (and for such additional periods as may be specified in this Section 9.10), Seller shall, at its own expense, provide and maintain in effect the insurance policies and minimum limits of coverage specified in this Section 9.10, and such additional coverage as may be required by Applicable Law, with insurance companies which are authorized to do business in the state in which the services are to be performed and which have an A.M. Best’s Insurance Rating of not less than A-:VII. The minimum insurance requirements specified in this Section 9.10 do not in any way limit or relieve Seller of any obligation assumed elsewhere in this Agreement, including, but not limited to, Seller’s defense and indemnity obligations. (i)

Workers’ Compensation Insurance with the statutory limits required by the state having jurisdiction over Seller’s employees;

(ii)

Employer’s Liability Insurance with limits of not less than:

1)

Bodily injury by accident – One Million dollars ($1,000,000) each accident;

2)

Bodily injury by disease – One Million dollars ($1,000,000) policy limit; and

3)

Bodily injury by disease – One Million dollars ($1,000,000) each employee; and

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(iii)

Commercial General Liability Insurance, (which, except with the prior written consent of Buyer and subject to Sections 9.10(a)(ii)(1) and (2), shall be written on an “occurrence,” not a “claims-made” basis), covering all operations by or on behalf of Seller arising out of or connected with this Agreement, including coverage for bodily injury, broad form property damage, personal and advertising injury, products/completed operations, and contractual liability. Such insurance shall bear a combined single limit per occurrence and annual aggregate of not less than one million dollars ($1,000,000), exclusive of defense costs, for all coverages. Such insurance shall contain standard cross-liability and severability of interest provisions.

If Seller elects, with Buyer’s written concurrence, to use a “claims made” form of Commercial General Liability Insurance, then the following additional requirements apply: 1)

The retroactive date of the policy must be prior to the Effective Date; and

2)

Either the coverage must be maintained for a period of not less than four years after the Agreement terminates, or the policy must provide for a supplemental extended reporting period of not less than four years after the Agreement terminates.

(iv)

Commercial Automobile Liability Insurance covering bodily injury and property damage with a combined single limit of not less than $1,000,000 per occurrence. Such insurance shall cover liability arising out of Seller’s use of all owned (if any), non-owned and hired automobiles in the performance of the Agreement.

(v)

Umbrella/Excess Liability Insurance, written on an “occurrence,” not a “claims-made” basis, providing coverage excess of the underlying Employer’s Liability, Commercial General Liability, and Commercial Automobile Liability insurance, on terms at least as broad as the underlying coverage, with limits of not less than $10,000,000 per occurrence and in the annual aggregate. The insurance requirements of this Section 9.10 can be provided by any combination of Seller’s primary and excess liability policies.

(b)

The insurance required in Section 9.10(a) apply as primary insurance to, without a right of contribution from, any other insurance maintained by or afforded to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, and employees, regardless of any conflicting provision in Seller's policies to the contrary. To the extent permitted by Applicable Law, Seller and its insurers are required to waive all rights of recovery from or subrogation against Buyer, its subsidiaries and affiliates, and their respective

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officers, directors, shareholders, agents, employees and insurers. The Commercial General Liability and Umbrella/Excess Liability insurance required above shall name Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents and employees, as additional insureds for liability arising out of Seller’s construction, ownership or Operation of the Generating Facility.

9.11

(c)

At the time this Agreement is executed, or within a reasonable time thereafter, and within a reasonable time after coverage is renewed or replaced, Seller shall furnish to Buyer certificates of insurance evidencing the coverage required in this Section 9.10, written on forms and with deductibles reasonably acceptable to Buyer. All deductibles, co-insurance and self-insured retentions applicable to the insurance above shall be paid by Seller. All certificates of insurance shall note that the insurers issuing coverage shall endeavor to provide Buyer with at least 30 days’ prior written notice in the event of cancellation of coverage. Buyer’s receipt of certificates that do not comply with the requirements stated herein, or Seller’s failure to provide certificates, does not limit or relieve Seller of the duties and responsibility of maintaining insurance in compliance with the requirements in this Section 9.10 and does not constitute a waiver of any of the requirements in this Section 9.10.

(d)

If Seller fails to comply with any of the provisions of this Section 9.10, Seller, among other things and without restricting Buyer’s remedies under the Applicable Law or otherwise, shall, at its own cost and expense, act as an insurer and provide insurance in accordance with the terms and conditions above. With respect to the required Commercial General Liability, Umbrella/Excess Liability and Commercial Automobile Liability insurance, Seller shall provide a current, full and complete defense to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, employees, assigns, and successors in interest, in response to a third party claim in the same manner that an insurer would have, had the insurance been maintained in accordance with the terms and conditions set forth above.

(e)

Seller has the right to self-insure to comply with Seller’s obligations under this Section 9.10. The insurance carrier or carriers and form of policy (including any deductible amount), or any plan for self-insurance shall be subject to review and approval by Buyer, which approval may not be unreasonably withheld, conditioned or delayed.

Nondedication. Notwithstanding any other provisions of this Agreement, neither Party dedicates any of the rights that are or may be derived from this Agreement or any part of its facilities involved in the performance of this Agreement to the public or to the service provided under this Agreement, and such service shall cease upon termination of this Agreement.

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9.12

Mobile Sierra. Notwithstanding any provision of this Agreement, neither Party will seek, nor will they support any third party in seeking, to prospectively or retroactively revise the rates, terms, or conditions of service of this Agreement through application or complaint to FERC pursuant to the provisions of Section 205, 206, or 306 of the Federal Power Act, or any other provisions of the Federal Power Act, absent prior written agreement of the Parties. Further, absent the prior agreement in writing by both Parties, the standard of review for changes to the rates, terms or conditions of service of this Agreement proposed by a Party, a non-Party or the FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 US 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 US 348 (1956).

9.13

Seller Ownership and Control of Generating Facility. Seller agrees, that, in accordance with FERC Order No. 697, upon request of Buyer, Seller shall submit a letter of concurrence in support of an affirmative statement by Buyer that the contractual arrangement set forth in this Agreement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR Section 35.42. Seller also agrees that it will not, in filings, if any, made subject to Order Nos. 652 and 697, claim that the contractual arrangement set forth in this Agreement conveys ownership or control of generation capacity from Seller to Buyer.

9.14

Simple Interest Payments. Except as specifically provided in this Agreement, any outstanding and past due amounts owing and unpaid by either Party under the terms of this Agreement shall be eligible to receive a Simple Interest Payment calculated using the Interest Rate for the number of days between the date due and the date paid.

9.15

Payments. Payments to be made under this Agreement shall be made, at Seller’s option, by check or electronic wire funds transfer.

9.16

Provisional Relief. The Parties acknowledge and agree that irreparable damage would occur if certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or the other security, to seek a preliminary injunction, temporary restraining order, or other provisional relief as a remedy for a breach of Sections 3.01, 3.02, 3.03, or 9.09 in any court of competent jurisdiction, notwithstanding the obligation to submit all other disputes (including all Claims for monetary damages under this Agreement) to arbitration pursuant to Section 10.01. The Parties further acknowledge and agree that the results of such arbitration may be rendered ineffectual without such provisional relief.

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Such a request for provisional relief does not waive a Party’s right to seek other remedies for the breach of the provisions specified above in accordance with Section 10.01, notwithstanding any prohibition against claim-splitting or other similar doctrine. The other remedies that may be sought include specific performance and injunctive or other equitable relief, plus any other remedy specified in this Agreement for such breach of the provision, or if this Agreement does not specify a remedy for such breach, all other remedies available at law or equity to the Parties for such breach. *** End of Article Nine ***

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ARTICLE TEN.

DISPUTE RESOLUTION

10.01 Dispute Resolution. Other than requests for provisional relief under Section 9.16, any and all disputes, Claims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which Disputes the Parties have been unable to resolve by informal methods, will first be submitted to mediation in accordance with the procedures described in Section 10.02, and if the Dispute is not resolved through mediation, then for final and binding arbitration in accordance with the procedures described in Section 10.03. 10.02 Mediation. Either Party may initiate mediation by providing Notice to the other Party of a written request for mediation, setting forth a description of the Dispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the panel of neutrals from JAMS or any other mutually acceptable non-JAMS Mediator, and in scheduling the time and place of the mediation. Such selection and scheduling will be completed within 45 days after Notice of the request for mediation. Unless otherwise agreed to by the Parties, the mediation will not be scheduled for a date that is greater than 120 days from the date of Notice of the request for mediation. The Parties covenant that they will participate in the mediation, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and costs will be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, will not be subject to discovery and will be confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them; provided, however, that evidence that is otherwise admissible or discoverable will not be rendered inadmissible or non-discoverable as a result of its use in the mediation. 10.03 Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation in accordance with Section 10.02 by providing Notice of a demand for binding arbitration before a single, neutral arbitrator (the “Arbitrator”) at any time following the unsuccessful conclusion of the mediation provided for in Section 10.02.

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The Parties will cooperate with one another in selecting the Arbitrator within 60 days after Notice of the demand for arbitration and will further cooperate in scheduling the arbitration to commence no later than 180 days from the date of Notice of the demand. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator will be appointed as provided for in California Code of Civil Procedure Section 1281.6. To be qualified as an Arbitrator, each candidate must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator will be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon Notice of a Party’s demand for binding arbitration, such Dispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, will be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regard to principles of conflicts of laws. Except as provided for in this Section 10.03, the arbitration will be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated. Absent the existence of such rules and procedures, the arbitration will be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration will be in Los Angeles, California, and discovery will be limited as follows: (a)

Before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment);

(b)

The initial disclosure will occur within 30 days after the initial conference with the Arbitrator or at such time as the Arbitrator may order;

(c)

Discovery may commence at any time after the Parties’ initial disclosure;

(d)

The Parties will not be permitted to propound any interrogatories or requests for admissions;

Article Ten

Dispute Resolution

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(e)

Discovery will be limited to 25 document requests (with no subparts), three lay witness depositions, and three expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents);

(f)

Each Party is allowed a maximum of three expert witnesses, excluding rebuttal experts;

(g)

Within 60 days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding;

(h)

Within 30 days after the initial expert disclosure, the Parties may designate a maximum of two rebuttal experts;

(i)

Unless the Parties agree otherwise, all direct testimony will be in form of affidavits or declarations under penalty of perjury; and

(j)

Each Party shall make available for cross-examination at the arbitration hearing its witnesses whose direct testimony has been so submitted.

Subject to Article Seven, the Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections 3.01, 3.02, 3.03 or 9.09. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator must, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs will be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail. Until such award is made, however, the Parties will share equally in paying the costs of the arbitration. *** End of Article Ten ***

Article Ten

Dispute Resolution

Page 63

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT A Definitions For purposes of this Agreement, the following terms and variations thereof have the meanings specified or referred to in this Exhibit A: “Actual HR” means the Heat Rate that must be used in accordance with and subject to the terms set forth in Section 2(a)(ii) of Exhibit S, which Heat Rate Buyer shall calculate, on the date of the commencement of the First Compliance Period, using the following formula: Actual HRn = The average of the Daily HRn for each delivery or flow date in the two (2) year period immediately preceding the commencement of the First Compliance Period Where: Daily HRn = [EPn – VOMn] / [GPn + GTn] Where: EPn = The average of the Day-Ahead hourly electric energy prices, as determined by the Integrated Forward Market (as defined in the CAISO Tariff) for (i) SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor, if Buyer is SCE or SDG&E, and (ii) NP15 Existing Zone Generation Trading Hub (formerly known as NP15), or its successor, if Buyer is PG&E; VOMn = Calendar month avoided variable O&M for the applicable month ($/kWh), per the Decision and CPUC Resolution E-4246; GPn = The applicable daily gas price index, which is (i) Platt’s Gas Daily (currently SoCalGas gas indices), if Buyer is SCE or SDG&E, or (ii) Platt’s Gas Daily (currently SoCalGas and PG&E Malin gas indices), if Buyer is PG&E; and GTn = The gas transportation rate for the applicable month, per CPUC Resolution E-4246. “Additional GHG Documentation” means the documentation necessary to allocate Free Allowances to electric energy delivered by Seller to Buyer, which documentation consists of the following, in each case for the time-period to which the Free Allowances are to apply: (a) the total amount of GHG emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, the Useful Thermal Energy Output of the Generating Facility, and the electric energy delivered to Buyer; (b) the Useful Thermal Energy Output of the Generating Facility; (c) the total electric energy produced by the Generating Facility, the electric energy

Exhibit A

Definitions

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

used to the serve the Site Host Load, and the electric energy delivered to Buyer; and (d) total fuel usage of the Generating Facility. “Agreement” has the meaning set forth in the Preamble. “Allowance” means a limited tradable authorization (whether in the form of a credit, allowance or other similar right), allocated to, issued to or purchased by, Seller, the Site Host or a Related Entity of Seller, with respect to the Generating Facility, to emit one MT of Greenhouse Gas, in accordance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), and as applied to the Greenhouse Gas emitted by the Generating Facility. “Allowance Cost” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “Allowed Firm Energy” is determined in Section 3(l) of Exhibit D. “Allowed Hourly Energy”, or “E”, is determined in Section 3(f) of Exhibit D. “Allowed Payment Energy”, or “APE”, is determined in Section 2(c) of Exhibit D. “Ambient Outage” means reductions in capacity due to that status of, or variations in, Site Host Load or ambient weather conditions. “Annual GHG Reports” has the meaning set forth in Section 3(a) of Exhibit S. “Applicable HR” has the meaning set forth in Section 1 of Exhibit S. “Applicable Laws” means all constitutions, treaties, laws, ordinances, rules, regulations, interpretations, permits, judgments, decrees, injunctions, writs and orders of any Governmental Authority or arbitrator that apply to either or both of the Parties, the Generating Facility or the terms of this Agreement. “Arbitrator” has the meaning set forth in Section 10.03. “As-Available Capacity”, or “AAC”, is determined in Section 3(c) of Exhibit D. “As-Available Capacity Payment”, or “ACP”, is determined in Section 3(b) of Exhibit D. “As-Available Capacity Price” means the price adopted by the CPUC in the Decision and in subsequent rulings of the CPUC implementing the Decision, or pursuant to any such other formula as the CPUC may adopt from time to time for As-Available Capacity Payments to be made to Buyer’s Qualifying Cogeneration Facilities for the applicable year, as set forth in Section 3(b) of Exhibit D, in dollars per kW-year.

Exhibit A

Definitions

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“As-Available Contract Capacity” means the electric energy generating capacity that Seller provides on an as-available basis for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). “Availability Credit Factor”, or “ACF”, is determined in Section 3(i) of Exhibit D. “Availability Incentive Payments” has the meaning set forth in the CAISO Tariff. “Availability Penalty Factor”, or “APF”, is determined in Section 3(n) of Exhibit D. “Availability Standards” has the meaning set forth in the CAISO Tariff. “Bankrupt” means with respect to any Person, such Person: (a) Files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it (which petition is not dismissed within 90 days); (b) Makes an assignment or any general arrangement for the benefit of creditors; (c) Otherwise becomes bankrupt or insolvent (however evidenced); (d) Has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets; or (e) Is generally unable to pay its debts as they fall due. “Benchmark Capacity” is determined, as applicable, in Section 3(a) of Exhibit D-1, Section 3(a) of Exhibit D-2, and Section 9(a) of Exhibit E. “Burner Tip Gas Price” or “BTGP” has the meaning set forth in Section 1 of Exhibit S. “Business Day” means any day except a Saturday, Sunday, the Friday after the United States Thanksgiving holiday, or a Federal Reserve Bank holiday that begins at 8:00 a.m. and end at 5:00 p.m. local time for the Party sending a Notice or payment or performing a specified action. “Buyer” has the meaning set forth in the Preamble. “Buyer Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy produced by the Generating Facility. “Buyer Parent Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy delivered to the CAISO for the CAISO Global Resource ID associated with the Generating Facility.

Exhibit A

Definitions

Page 3

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Buyer Projected Energy Forecast” has the meaning set forth in Section 2(a) of Exhibit G. “CAISO” means the California Independent System Operator Corporation or successor entity that dispatches certain generating units, supplies certain loads and controls the transmission facilities of entities that (a) own, operate and maintain transmission lines and associated facilities or have entitlements to use certain transmission lines and associated facilities, and (b) have transferred to the CAISO or its successor entity operational control of such facilities or entitlements. “CAISO-Approved Meter” means any revenue quality, electric energy measurement meter furnished by Seller, that (a) is designed, manufactured and installed in accordance with the CAISO’s metering requirements, or, to the extent that the CAISO’s metering requirements do not apply, Prudent Electrical Practices, and (b) includes all of the associated metering transformers and related appurtenances that are required in order to measure the net electric energy output from the Generating Facility. “CAISO-Approved Quantity” means the total quantity of electric energy that Buyer Schedules with the CAISO and the CAISO approves in its final schedule which is published in accordance with the CAISO Tariff. “CAISO Charges” means the debits, costs, fees, penalties, sanctions, interest or similar charges, including imbalance energy charges, that are directly assigned by the CAISO to the CAISO Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement. “CAISO Charges Invoice” has the meaning set forth in Section 5 of Exhibit G. “CAISO Controlled Grid” has the meaning set forth in the CAISO Tariff. “CAISO Forced Outage Report” means a complete copy of a forced outage report in a form reasonably acceptable to Buyer which includes detailed information regarding the event, including the affected Generating Unit, outage start date and time, estimation of outage duration, MW unavailable and summary of work to be performed. “CAISO Global Resource ID” means the number or name assigned by the CAISO to the CAISOApproved Meter. “CAISO Revenues” means the credits, fees, payments, revenues, interest or similar benefits, including imbalance energy payments, that are directly assigned by the CAISO to the CAISO Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement.

Exhibit A

Definitions

Page 4

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“CAISO Tariff” means the California Independent System Operator Corporation Operating Agreement and Tariff, including the rules, protocols, procedures and standards attached thereto, as the same may be amended or modified from time to time and approved by the FERC. “Capacity Attributes” means any and all current or future defined characteristics, certificates, tag, credits, ancillary service attributes, or accounting constructs, howsoever entitled, other than Resource Adequacy Benefits, attributed to or associated with the electricity generating capability of the Generating Facility. “Capacity Credit Hours”, or “CCH”, is determined in Section 3(m) of Exhibit D. “Capacity Credit Period” is determined in Section 3(b)(iv) of Exhibit E. “Capacity Payment Allocation Factors”, or “CAF”, means the TOD Period factors which are used to calculate the TOD Period Capacity Payment, as set forth in the table in Section 3(a) of Exhibit D. “Capacity Performance Requirement”, or “CR”, means the values set forth in Section 1.04. “CARB” means California Air Resources Board, or any successor entity. “CARB Annual Report” has the meaning set forth in Section 3(a)(i) of Exhibit S. “CARB Mandatory GHG Emissions Annual Report” means the mandatory reporting regulations approved by CARB in December 2007, which became effective in January 2009, pursuant to the requirements set forth in the California Global Warming Solutions Act of 2006 for the reporting of Greenhouse Gas by major sources. “CEC” means the California Energy Commission, or any successor entity. “CFR” means the Code of Federal Regulations, as may be amended from time to time. “Check Meter” means the Buyer revenue-quality meter section or meter(s), which Buyer may require at its discretion, as set forth in Section 3.08(b) and will include those devices normally supplied by Buyer or Seller under the applicable utility Electric Service Requirements. “Claiming Party” has the meaning set forth in Section 5.02. “Claims” means all third party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys’ fees and court costs, whether incurred by settlement or otherwise, and whether such claims or actions are threatened or filed before or after the termination of this Agreement. “Collateral Assignment Agreement” has the meaning set forth in Section 9.05.

Exhibit A

Definitions

Page 5

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Confidential Information” means all oral or written communications exchanged between the Parties on or after the Effective Date relating to the implementation of this Agreement, including information related to Seller’s compliance with operating and efficiency standards applicable to a “qualifying cogeneration facility” (as contemplated in 18 CFR Part 292, Section 292.205). Confidential Information does not include (i) information which is in the public domain as of the Effective Date or which comes into the public domain after the Effective Date from a source other than from the other Party, (ii) information which either Party can demonstrate in writing was already known to such Party on a non-confidential basis before the Effective Date, (iii) information which comes to a Party from a bona fide third-party source not under an obligation of confidentiality, or (iv) information which is independently developed by a Party without use of or reference to Confidential Information or information containing Confidential Information. “Control Area” means the electric power system (or combination of electric power systems) under the operational control of the CAISO or any other electric power system under the operational control of another organization vested with authority comparable to that of the CAISO. “Converted Physical Trade”, or “CPT”, means the quantity from Physical Trades, in MWh, that did not pass CAISO’s physical validation of the IFM. “Converted Physical Trade Price” means the price, in dollars per MWh, used by the CAISO to settle the quantity, in MWh, associated with the Converted Physical Trade. “Costs” means, with respect to the Non-Defaulting Party, brokerage fees, commissions, legal expenses and other similar third party transaction costs and expenses reasonably incurred by such Party in entering into any new arrangement which replaces this Agreement. “CPUC” means the California Public Utilities Commission, or any successor entity. “CPUC Approval” means a final and non-appealable order of the CPUC, without conditions or

modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. “Curtailment Period” means a time period for which Seller is requested by CAISO or a Transmission Provider to curtail its Power Product for Force Majeure or otherwise. “D.” has the meaning set forth in Recital A.

Exhibit A

Definitions

Page 6

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Day-Ahead” has the meaning set forth in the CAISO Tariff. “Day-Ahead Market” has the meaning set forth in the CAISO Tariff. “Day-Ahead Price” means the LMPQF, as set forth in Section 1 of Exhibit S. “Day-Ahead Schedule” has the meaning set forth in the CAISO Tariff. “Decision” has the meaning set forth in Recital A. “Defaulting Party” has the meaning set forth in Section 6.01(a). “Delivery Point” has the meaning set forth in Section 1.03. “Disclosure Order” has the meaning set forth in Section 9.09(b). “Dispute” has the meaning set forth in Section 10.01. “Early Termination Date” has the meaning set forth in Section 6.02(a). “Earned Capacity Hours”, or “ECH”, means the number of firm capacity equivalent available hours determined by dividing the Firm TOD Energy by the Firm Contract Capacity, as set forth in Section 3(j) of Exhibit D. “Effective Date” has the meaning set forth in the Preamble. “Emergency Condition” has the meaning set forth in the Transmission Provider’s LGIA or SGIA with Seller, or the distribution-level FERC-jurisdictional interconnection agreement with Seller, as applicable; provided, however, that if Seller interconnects pursuant to Tariff Rule 21, “Emergency Condition” means “Emergency”, as defined in such Tariff Rule 21. “Equitable Defense” means any Bankruptcy or other laws affecting creditors’ rights generally, and with regard to equitable remedies, the discretion of the court before which proceedings to obtain same may be pending. “Equity Investment” means an acquisition by a Lender of an ownership interest in the form of stock, membership or partnership interest of Seller or the immediate parent of Seller under which Seller retains the right to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s rights to enforce its ownership interest in Seller or the immediate parent of Seller, as applicable, in the event of a default by Seller or the immediate parent of Seller under Lender’s equity acquisition agreement or the partnership agreement, operating agreement, or other agreement governing the relationship between the equity owners of the Generating Facility. “Event of Default” has the meaning set forth in Section 6.01.

Exhibit A

Definitions

Page 7

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Existing PPA” has the meaning set forth in Section 1.01. “Existing Qualifying Cogeneration Facility” means a Generating Facility that commenced Parallel Operation before the Settlement Effective Date, and that, as of the Settlement Effective Date, (a) is a Qualifying Cogeneration Facility, and (b) is the generating facility under the Existing PPA. “Expected Term Year Energy Production” means the Metered Energy quantity expected to be produced by the Generating Facility during each Term Year, as set forth in Section 1.02(e). “Federal Funds Effective Rate” means the rate for that day opposite the caption “Federal Funds (effective)” as set forth in the weekly statistical release as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System. “FERC” means the Federal Energy Regulatory Commission, or any successor entity. “FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.05 in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. “Financial Consolidation Requirement” has the meaning set forth in Section 3.20(a). “Financial Incentives” means any and all financial incentives, benefits or credits associated with the Generating Facility, or the ownership or Operation thereof, or the electrical or thermal output of the Generating Facility, including any production or investment tax credits, real or personal property tax credits or sales or use tax credits, but not including any Green Attributes, Capacity Attributes or Resource Adequacy Benefits. “Firm Capacity Payment”, or “FCP”, has the meaning set forth in Section 3(g) of Exhibit D. “Firm Capacity Price” or “CP” is set forth in Section 1.06(a), in dollars per kW-year. “Firm Contract Capacity”, or “FCC”, means the monthly generating capacity that Seller commits to have available at the Site for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c).

Exhibit A

Definitions

Page 8

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Firm TOD Energy”, or “FE”, has the meaning set forth in Section 3(k) of Exhibit D. “First Compliance Period” means the first period of time for compliance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation). There will be no more than a single First Compliance Period. “First Penalty Month” has the meaning set forth in Section 3(b) of Exhibit I. “Floor Test Term” means the date that the First Compliance Period commences, for a period of three years. “Forced Outage” has the meaning set forth in the CAISO Tariff. “Force Majeure” means any event or circumstance to the extent beyond the control of, and not the result of the negligence of, or caused by, the Party seeking to have its performance obligation excused thereby, which by the exercise of due diligence such Party could not reasonably have been expected to avoid and which by exercise of due diligence it has been unable to overcome. Force Majeure does not include: (a) A failure of performance of any other Person, including any Person providing electric transmission service or fuel transportation to the Generating Facility, except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure event; (b) Failure to timely apply for or obtain Permits or other credits required to Operate the Generating Facility; (c) Breakage or malfunction of equipment (except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure); or (d) A lack of fuel of an inherently intermittent nature such as wind, water, solar radiation or waste gas or waste derived fuel. “Force Majeure Credit Value”, or “FCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Force Majeure curtailment requested by Buyer, determined in accordance with Section 3 of Exhibit D-1. “Forecast” means the hourly forecast of (a) the total electric energy production of the Generating Facility (in MWh) when the Generating Facility is not PIRP-eligible or Buyer is not Scheduling Coordinator net of the Site Host Load and Station Use, or (b) the available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator net of the Site Host Load and Station Use.

Exhibit A

Definitions

Page 9

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Forward Settlement Amount” means the Non-Defaulting Party’s Costs and Losses on the one hand, netted against its Gains, on the other. If the Non-Defaulting Party’s Gains exceed its Costs and Losses, then the Forward Settlement Amount shall be zero dollars. If the Non-Defaulting Party’s Costs and Losses exceed its Gains, then the Forward Settlement Amount shall be an amount owing to the Non-Defaulting Party. The Forward Settlement Amount does not include consequential, incidental, punitive, exemplary or indirect or business interruption damages. “Free Allowance” means any Allowance freely allocated to Seller or the Generating Facility by CARB or an authorized Governmental Authority (or any entity authorized by such Governmental Authority). “Free Allowance Notice” means the Notice, delivered by Seller to Buyer in accordance with this Agreement, that sets forth the aggregate quantity of Free Allowances received by Seller during the applicable time-period and sets forth the allocation of such Free Allowances in accordance with the following: (i)

The allocation of Free Allowances by the CARB (or any other Governmental Authority) to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable time-period; or

(ii)

If the CARB (or any other Governmental Authority) does not allocate Free Allowances received by Seller as described in subsection (i) above, then Seller shall set forth in the Free Allowance Notice the quantity of Free Allowances allocated to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable timeperiod (FAd) utilizing the following formula: FAd = FAt * [Ge/(Ge+ Gt)] * [Ed/(Esh + Ed)] Where: FAt = Total number of Free Allowances received by Seller with respect to the Generating Facility for the applicable time-period; Ge (in MTs) = Emissions of Greenhouse Gas attributed to the total amount of electric energy produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Gt (in MTs) = Emissions of Greenhouse Gas attributed to the Useful Thermal Energy Output produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the

Exhibit A

Definitions

Page 10

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Ed (in kWh) = Electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period; and Esh (in kWh) = Electric energy generated by the Generating Facility and used to serve the Site Host Load for the applicable time-period; or (iii)

If the CARB (or any other Governmental Authority) does not allocate the Free Allowances received by Seller, as described in (i) above, and there is no available formula in any applicable rule or regulation for the calculation of Ge and Gt, as described in (ii) above, then Seller shall include in the Free Allowance Notice the total amount of emissions of Greenhouse Gas attributed to the electric energy period (Ge, in MTs) and the Useful Thermal Energy Output (Gt, in MTs) produced by the Generating Facility for the applicable time-period based on the two following formulas: Ge = G * (Useful Power Output / (Useful Power Output + Useful Thermal Energy Output)) Gt = G * (Useful Thermal Energy Output / (Useful Power Output + Useful Thermal Energy Output)) Where: G (in MTs) = Total emissions of Greenhouse Gas produced by the Generating Facility for the applicable time-period; Useful Power Output (in MMBtu) = As defined in 18 CFR §292.202(g), or any successor thereto; Useful Thermal Energy Output (in MMBtu) = As defined in 18 CFR §292.202(h), or any successor thereto; Upon determining Ge and Gt in subsection (iii) above, Seller shall then calculate for and provide the quantity of Free Allowances attributed to electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period (FAd) using the formula set forth in subsection (ii) of this definition.

“GAAP” means generally accepted accounting principles for financial reporting in the United States, consistently applied.

Exhibit A

Definitions

Page 11

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Gains” means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), as of the Early Termination Date resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the gain of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remaining Term and shall include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the gain of economic benefits, then the NonDefaulting Party may use information available to it internally. “Generating Facility” means the Generating Unit(s) described in Section 1.02 and Exhibit B, including all other materials, equipment, systems, structures, features and improvements necessary for these Generating Units to produce electric energy and thermal energy, excluding the Site, land rights and interests in land. “Generating Unit” means one or more generating equipment combinations typically consisting of prime mover(s), electric generator(s), electric transformer(s), steam generator(s) and air emission control devices. The references to the term Generating Unit shall be applicable only to Generating Unit #2 and Generating Unit #4 throughout the Term. “Generating Unit #2” means the Generating Unit described in Section 1(a) of Exhibit B of this Agreement. “Generating Unit #4” means the Generating Unit described in Section 1(b) of Exhibit B of this Agreement. “Generation Operations Center” means the location of Buyer’s real-time operations personnel. “Generator Operator” means the Person that Operates the Generating Facility and performs the functions of supplying electric energy and interconnected operations services within the meaning of the NERC Reliability Standards.

Exhibit A

Definitions

Page 12

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Generator Operator Obligations” means the obligations of a Generator Operator as set forth in all applicable NERC Reliability Standards. “Generator Owner” means the Person that owns the Generating Facility and has registered with the NERC as the Person responsible for complying with all NERC Reliability Standards applicable to the owner of the Generating Facility. “Generator Owner Obligations” means the obligations of a Generator Owner as set forth in all applicable NERC Reliability Standards. “GHG Allowance Price” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “GHG Auction” means any auction or other sale-by-bid event applicable to California and by an authorized Governmental Authority (or any entity authorized by such Governmental Authority) for the sale of Allowances. “GHG Charges” has the meaning set forth in Section 1 of Exhibit S. “GHG Compliance Costs” means the cost of Allowances, as determined in accordance with Exhibit S. “GHG Floor Test” has the meaning set forth in Section 2(a) of Exhibit S. “Governmental Authority” means (a) any federal, state, local, municipal or other government, (b) any governmental, regulatory or administrative agency, commission, or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power, or (c) any court or governmental tribunal. “Governmental Charges” has the meaning as set forth in Section 8.02. “Green Attributes” means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to

Exhibit A

Definitions

Page 13

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1 (3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. “Greenhouse Gas” or “GHG” means emissions released into the atmosphere of carbon dioxide (CO2), nitrous oxide (N2O) and methane (CH4), which are produced as the result of combustion or transport of fossil fuels. Other greenhouse gases may include hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6), which are generated in a variety of industrial processes. Greenhouse gases may be defined or expressed in terms of a MT of CO2equivalent, in order to allow comparison between the different effects of gases on the environment; provided, however, that the definition of the term “Greenhouse Gas”, as set forth in

1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program.

Exhibit A

Definitions

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Southern California Edison RAP ID #2811, Kern River Cogeneration Company

the immediately preceding sentence, shall be deemed revised to include any update or other change to such term by the CARB or any other Governmental Authority. “Heat Rate” means, for purposes of this Agreement, the value obtained, in BTU per kWh, when the fuel input, on a Higher Heating Value basis, in BTU is divided by generation, net of Station Use, in kWh. “Higher Heating Value” means the high or gross heat content of the fuel with the heat of vaporization included (the water vapor is assumed to be in a liquid state). “Host Site” means the site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Related Entities located at such site. “Hour-Ahead Scheduling Deadline” means 30 minutes before the deadline established by the CAISO for the submission of schedules for the applicable hour. “Hourly Credit Value” is determined, as applicable, in Section 3(b) of Exhibit D-1, Section 3(b) of Exhibit D-2 and Section 9(b)(i) of Exhibit E. “Hourly Debit Value” is determined in Section 9(b)(ii) of Exhibit E. “Hourly Location Adjustment”, or “LA”, has the meaning set forth in Section 1 of Exhibit S. “Hourly Power Output” means an hourly rate of electric energy delivery, in kWh per hour, that is equal to the Metered Energy for one hour, in kWh, divided by one hour. “IFM” (i.e., the Integrated Forward Market) has the meaning set forth in the CAISO Tariff. “IFM Load Uplift Obligation” means the obligation of a Scheduling Coordinator to pay its share of unrecovered IFM Bid Costs (as defined in the CAISO Tariff) paid to resources through Bid Cost Recovery (as defined in the CAISO Tariff). “IFRS” has the meaning set forth in Section 3.20(b)(iii). “Incipient Event of Default” has the meaning set forth in Section 9.05(a). “Interconnection Study” means a study prepared by or on behalf of the Transmission Provider or the CAISO to evaluate the impact of the interconnection of the Generating Facility to the Transmission Provider’s electric system or the applicable Control Area operator’s electric grid. “Interest Rate” means an annual rate equal to the rate published in The Wall Street Journal as the “Prime Rate” (or, if more than one rate is published, the arithmetic mean of such rates) as of the date payment is due plus two percentage points; provided, however, that in no event shall the Interest Rate exceed the maximum interest rate permitted by Applicable Laws.

Exhibit A

Definitions

Page 15

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Inter-SC Trade” means a trade between Scheduling Coordinators of electric energy, Ancillary Service (as defined in the CAISO Tariff), or IFM Load Uplift Obligation in accordance with the CAISO Tariff. “JAMS” means the Judicial Arbitration and Mediation Services, Inc. or any successor entity. “kW” means a kilowatt (1,000 watts) of electric capacity or power output. “kWh” means a kilowatt-hour (1,000 watt-hours) of electric energy. “LAR” means local area reliability, which is any program of localized resource adequacy requirements established for jurisdictional load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by another Local Regulatory Authority having jurisdiction over the load serving entity. LAR may also be known as local resource adequacy, local RAR, or local capacity requirement in other regulatory proceedings or legislative actions. “LAR Showings” means the LAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction over the load serving entity. “Lease” means one or more agreements whereby Seller leases the Site(s) described in Section 1.02 and Exhibit B from a third party, the term of which lease begins on or before the Term Start Date and extends at least through the Term End Date. “Lender” means any third-party institution or entity or successor in interest or assignees that either (i) purchases the Generating Facility and then leases it to Seller under a Sale-Leaseback Transaction, or (ii) provides development, bridge, construction, or permanent debt or tax equity financing or refinancing (including an Equity Investment) for the Generating Facility to Seller or credit support in connection with this Agreement. “LGIA” (i.e., Large Generator Interconnection Agreement or Standard Large Generator Interconnection Agreement) has the meaning set forth in the CAISO Tariff. “Limited TOD Energy”, or “LE”, has the meaning set forth in Section 3(e) of Exhibit D. “LMPQF” has the meaning set forth in Section 1 of Exhibit S. “LMPTrading Hub” has meaning set forth in Section 1 of Exhibit S. “Local Regulatory Authority” has the meaning set forth in the CAISO Tariff. “Locational Marginal Price” has the meaning set forth in the CAISO Tariff.

Exhibit A

Definitions

Page 16

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Losses” means, with respect to any Party, an amount equal to the present value of the economic loss to it if any (exclusive of Costs), as of the Early Termination Date, resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the loss of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remainder of the Term and must include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the loss of economic benefits, then the Non-Defaulting Party may use information available to it internally. “MAEm” has the meaning set forth in Section 3(a) of Exhibit I. “MAE Failure” has the meaning set forth in Section 3(b) of Exhibit I. “Maintenance Credit Value”, or “MCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Maintenance Outage or a Major Overhaul which has been properly scheduled in accordance with Exhibit E. “Maintenance Debit Value” is a value indicating how much allowance is used when Seller requests credit for a Maintenance Outage or a Major Overhaul in accordance with Exhibit E. “Maintenance Outage” means a time period during which Seller plans to reduce the Power Output of the Power Product, in full or in part, in order to facilitate maintenance work on the Generating Facility, other than a Major Overhaul. “Major Overhaul” means a time period during which Seller plans to remove the Generating Facility from Operation in order to dismantle the Generating Facility’s equipment for inspections, repairs or replacement, with the goal that such equipment will be reassembled and made available for Operation. “Major Overhaul Allowance” is a value indicating a Term-Year maximum allowance with which Seller can request credit for a Major Overhaul in accordance with Exhibit E.

Exhibit A

Definitions

Page 17

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Market Disruption Event” means, with respect to any MHR Source, any of the following events: (i) the permanent discontinuation or material suspension of trading in the exchange or in the market specified for determining a Market Heat Rate; (ii) the temporary or permanent discontinuance or unavailability of the MHR Source; or (iii) the temporary or permanent closing of any exchange specified for determining a Market Heat Rate. For purposes of this definition, “temporary” means five (5) or more continuous Trading Days. “Market Heat Rate” means the 12-month forward market heat rate, calculated for each calendar pricing month utilizing the methodology set forth in Commission Decision 07-09-040 and Commission Resolution E-4246 for SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor. Unless otherwise agreed to by the Parties, this definition of Market Heat Rate will not be updated by any subsequent decision, ruling or order by the CPUC. “Maximum Allowed Capacity”, or “MAC”, is determined in Section 3(d) of Exhibit D. “Maximum Firm Capacity Payment”, or “MFCP”, means the maximum payment that Seller can earn during a year for the delivery of Firm Contract Capacity that is calculated in accordance with the procedure set forth in Section 3(h) of Exhibit D. “Mediator” has the meaning set forth in Section 10.02. “Metered Amounts” means the quantity of electric energy, expressed in kWh, as recorded by (i) the CAISO-Approved Meter(s), which quantity may include compensation factors introduced by the CAISO into the CAISO-Approved Meter(s), or (ii) Check Meter(s), as applicable. “Metered Energy” means the quantity of electric energy, expressed in kWh, as measured by (i) the CAISO-Approved Meter(s), which quantity will be adjusted so as not to include compensation factors, if any, introduced by the CAISO into the CAISO-Approved Meter(s) other than (x) electric energy consumed within the generator collection system as losses between the generator(s) and the high voltage side of the Generating Facility output transformer(s) and, (y) if applicable, the Generating Facility’s radial line losses, or (ii) Check Meters, as applicable, in each case for the specified Metering Interval. “Metering Interval” means the smallest measurement time period over which data are recorded by the CAISO-Approved Meters or Check Meters. “MHR Source” the relevant publications used to determine the Market Heat Rate. “Monthly Contract Payment” has the meaning set forth in Section 4.01. “Monthly Scheduling Fee” is described in Section 4(b) of Exhibit G. “MT” means metric ton(s). “MW” means a megawatt (1,000,000 watts) of electric capacity or power output.

Exhibit A

Definitions

Page 18

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“MWh” means a megawatt-hour (1,000,000 watt-hours) of electric energy or power output. “NERC” means the North American Electric Reliability Corporation, or any successor entity. “NERC Reliability Standards” means the most recent version of those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by the NERC and approved by the applicable regulatory authorities, which are available at http://www.nerc.com/files/Reliability_Standards_Complete_Set.pdf, or any successor thereto. “NERC Standards Non-Compliance Penalties” means any and all monetary fines, penalties, damages, interest or assessments by the NERC, the CAISO, the WECC, a Governmental Authority or any Person acting at the direction of a Governmental Authority arising from or relating to a failure to perform the obligations of Generator Operator or Generator Owner as set forth in the NERC Reliability Standards. “Net Contract Capacity”, or “NCC”, means the sum of Firm Contract Capacity and As-Available Contract Capacity, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). Net Contract Capacity may not exceed PMax. “Net Qualifying Capacity” has the meaning set forth in the CAISO Tariff. “Non-Availability Charges” has the meaning set forth in the CAISO Tariff. “Non-Defaulting Party” has the meaning set forth in Section 6.02. “Notice” means notices, requests, statements or payments provided in accordance with Section 9.07 and Exhibit N. “OMAR” means the Operational Metering Analysis and Reporting System operated and maintained by the CAISO as the repository of settlement quality meter data, or any successor thereto. “Operate,” “Operating,” or “Operation” means to provide (or the provision of) all the operation, engineering, purchasing, repair, supervision, training, inspection, testing, protection, use management, improvement, replacement, refurbishment, retirement, and maintenance activities associated with operating the Generating Facility in order to produce the Power Product in accordance with Prudent Electrical Practices. “Outage” has the meaning set forth in the CAISO Tariff. “Outage Schedule” has the meaning set forth in Section 2(a) of Exhibit R.

Exhibit A

Definitions

Page 19

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Outage Schedule Submittal Requirements” describes the obligations of Seller to submit maintenance and planned outage schedules (as defined in the CAISO Tariff under WECC rules) to Buyer 24 months in advance, as set forth in Exhibit R. “Parallel Operation” means the Generating Facility’s electrical apparatus is connected to the Transmission Provider’s system and the circuit breaker at the point of common coupling is closed. The Generating Facility may be producing electric energy or consuming electric energy at such time. “Party” has the meaning set forth in the Preamble. “Peak Months” means June, July, August and September. “Penalized As-Available Contract Capacity” has the meaning set forth in Section 3(b)(ii) of Exhibit I. “Penalized Firm Contract Capacity” has the meaning set forth in Section 3(b)(i) of Exhibit I. “Performance Tolerance Band Lower Limit” is determined in Section 1 of Exhibit K. “Performance Tolerance Band Upper Limit” is determined in Section 1 of Exhibit K. “Permits” means all applications, approvals, authorizations, consents, filings, licenses, orders, permits or similar requirements imposed by any Governmental Authority, or the CAISO, in order to develop, construct, Operate, maintain, improve, refurbish or retire the Generating Facility or to Forecast or deliver the electric energy produced by the Generating Facility to Buyer. “Person” means an individual, partnership, corporation, business trust, limited liability company, limited liability partnership, joint stock company, trust, unincorporated association, joint venture or other entity or a Governmental Authority. “PGA” (i.e., Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Physical Trade” has the meaning set forth in the CAISO Tariff. “Physical Trade Settlement Amount” means the dollar amount calculated in accordance with Exhibit L. “PIRP” (i.e., Participating Intermittent Resource Program) means the CAISO’s intermittent resource program initially established pursuant to Amendment No. 42 of the CAISO Tariff in Docket No. ER02-922-000, or any successor program that Buyer determines accomplishes a similar purpose. “PMax” has the meaning set forth in the CAISO Tariff.

Exhibit A

Definitions

Page 20

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“PNode” has the meaning set forth in the CAISO Tariff. “Power Output” means the average rate of electric energy delivery during one Metering Interval, converted to an hourly rate of electric energy delivery, in kWh per hour, that is equal to the product of Metered Energy for one Metering Interval, in kWh per Metering Interval, times the number of Metering Intervals in a one-hour period. “Power Product” means (a) the Net Contract Capacity and (b) all electric energy produced by the Generating Facility, net of all Station Use and any and all of the Site Host Load. “PPT” means Pacific Daylight time when California observes Daylight Savings Time and Pacific Standard Time otherwise. “Primary Fuel” means the fuel or combination of fuels that are provided for in the Permits applicable to the Generating Facility. “Product” means the Power Product and the Related Products. “Project” means the Generating Facility. “Prudent Electrical Practices” means those practices, methods and acts that would be implemented and followed by prudent operators of electric generating facilities in the Western United States, similar to the Generating Facility, during the relevant time period, which practices, methods and acts, in the exercise of prudent and responsible professional judgment in the light of the facts known at the time a decision was made, could reasonably have been expected to accomplish the desired result consistent with good business practices, reliability and safety. Prudent Electrical Practices includes, at a minimum, those professionally responsible practices, methods and acts described in the preceding sentence that comply with the manufacturer’s warranties, restrictions in this Agreement, and the requirement of Governmental Authorities, WECC standards, the CAISO and Applicable Laws. Prudent Electrical Practices shall include taking reasonable steps to ensure that: (a) Equipment, materials, resources and supplies, including spare parts inventories, are available to meet the Generating Facility’s needs; (b) Sufficient operating personnel are available at all times and are adequately experienced, trained and licensed as necessary to Operate the Generating Facility properly and efficiently, and are capable of responding to reasonably foreseeable emergency conditions at the Generating Facility and Emergencies whether caused by events on or off the Site; (c) Preventative, routine, and non-routine maintenance and repairs are performed on a basis that ensures reliable, long term and safe operation of the Generating Facility, Exhibit A

Definitions

Page 21

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

and are performed by knowledgeable, trained and experienced personnel utilizing proper equipment and tools; (d) Appropriate monitoring and testing are performed to ensure equipment is functioning as designed; (e) Equipment is not operated in a reckless manner, in violation of manufacturer’s guidelines or in a manner unsafe to workers, the general public or the Transmission Provider’s electric system, or contrary to environmental laws, permits or regulations or without regard to defined limitations, such as flood conditions, safety inspection requirements, operating voltage, current, volt ampere reactive (VAR) loading, frequency, rotational speed, polarity, synchronization, and control system limits; and (f) Equipment and components designed and manufactured to meet or exceed the standard of durability that is generally used for electric energy generation operations in the Western United States and will function properly over the full range of ambient temperature and weather conditions reasonably expected to occur at the Site and under both normal and emergency conditions. “PTSAi” has the meaning set forth in Section 2 of Exhibit L. “PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95-617, as amended from time to time. “QF PGA” (i.e., Qualifying Facility Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Qualifying Cogeneration Facility” means an electric energy generating facility that: (a)

Complies with the “qualifying cogeneration facility” definition and other requirements (including the requirements set forth in 18 CFR Part 292, Section 292.205) established by PURPA and any FERC rules as amended from time to time implementing PURPA, as set forth in 18 CFR Part 292, Section 292.203 et seq.; and

(b)

Has filed with the FERC (i) an application for FERC certification, pursuant to 18 CFR Part 292, Section 292.207(b)(1), which the FERC has granted, or (ii) a notice of selfcertification pursuant to 18 CFR Part 292, Section 292.207(a).

“RAR” means the resource adequacy requirements established for load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by a Local Regulatory Authority or other Governmental Authority having jurisdiction. “RAR Showings” means the RAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (or, to the extent authorized by the CPUC, to

Exhibit A

Definitions

Page 22

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

the CAISO), pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction. “Real-Time Forced Outage” means a Forced Outage which occurs only after 5:00 p.m. PPT on the day before the Trading Day. “Real-Time Market” has the meaning set forth in the CAISO Tariff. “Real-Time Price” means the Real-Time Market price for Uninstructed Imbalance Energy (as defined in the CAISO Tariff) or any successor price for short-term imbalance energy, as such price or successor price is defined in the CAISO Tariff, that would apply to the Generating Facility, which values are, as of the Effective Date, posted by the CAISO on its website. The values used in this Agreement will be those appearing on the CAISO website on the eighth Business Day of the calendar month following the month for which such prices are being applied. “Reference Market-Maker” means a leading dealer in the electric energy market that is not an Related Entity of either Party (or of a Trade Organization) and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker. “Related Entity” means, with respect to a party, any Person that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with such party. For purposes of this Agreement, “control” means the direct or indirect ownership of 50% or more of the outstanding capital stock or other equity interests having ordinary voting power. “Related Products” means (i) with respect to Resource Adequacy Benefits (a) that portion of the Resource Adequacy Benefits that are associated with the Firm Contract Capacity, and (b) to the extent that there are Resource Adequacy Benefits associated with the generating capacity of the Generating Facility other than the Firm Contract Capacity, that portion of the Resource Adequacy Benefits that are not associated with the Firm Contract Capacity and that are in excess of those Resource Adequacy Benefits used by Seller or by a Site Host, both in connection with the Host Site, to meet a known and established resource adequacy obligation under any Resource Adequacy Ruling at the point in time when the Resource Adequacy Benefits are to be used, and (ii) any Green Attributes, Capacity Attributes and all other attributes associated with the electric energy or capacity of the Generating Facility (but not including any Financial Incentives) that are in excess of those Green Attributes, Capacity Attributes or other attributes used, or retained for future use, by Seller or a Site Host, both in connection with the Host Site, to meet a known and established, at the point in time when the relevant attribute(s) are to be used or retained, obligation under Applicable Law. “Renewable Energy Credit” has the meaning set forth in Public Utilities Code Section 399.12(g), as may be amended from time to time or as further defined or supplemented by Applicable Law.

Exhibit A

Definitions

Page 23

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Resource Adequacy Benefits” means the rights and privileges attached to the Generating Facility that satisfy any Person’s resource adequacy obligations, as those obligations are set forth in any Resource Adequacy Rulings and shall include any local, zonal or otherwise locational attributes associated with the Generating Facility. “Resource Adequacy Resource” has the meaning set forth in the CAISO Tariff. “Resource Adequacy Rulings” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 0606-024, 06-07-031 and any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable Governmental Authority, as such CPUC decisions, rulings, laws, rules or regulations may be amended or modified from time to time during the Term. “RPS Program” means the State of California Renewable Portfolio Standard Program, as codified at California Public Utilities Code Section 399.11, et seq. “Sale-Leaseback Transaction” means a transaction in which Seller (i) sells the Generating Facility to a Lender providing tax equity financing to Seller and (ii) leases the Generating Facility from Lender under an agreement authorizing Seller to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s right to terminate the lease in the event of a default by Seller as set forth in the agreement between Seller and Lender. “Schedule” means the action of the Scheduling Coordinator, or its designated representatives, of notifying, requesting, and confirming to the CAISO, the CAISO-Approved Quantity of electric energy. “Scheduled Amount” means the Day-Ahead Schedule comprised of the quantity (in MWh) of electric energy expected to be produced by the Generating Facility that is scheduled from Seller or Seller’s Scheduling Coordinator to Buyer in a Physical Trade in the IFM. “Scheduled Power Offline” is described in Section 3(b)(v) of Exhibit E. “Scheduling Coordinator” means a Person certified by the CAISO for the purposes of undertaking the functions specified in Exhibit G. “Scheduling Fee” means the Monthly Scheduling Fee and the SC Set-Up Fee. “SC Replacement Date” has the meaning set forth in Section 7(b) of Exhibit G. “SC Set-Up Fee” is described in Section 4(a) of Exhibit G. “SC Trade Settlement Amount” means the amount(s) determined in accordance with Exhibit M.

Exhibit A

Definitions

Page 24

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“SC Trade Tolerance Band” means the greater of (a) three percent of the Scheduled Amount or (b) one MW. “SDD Administrative Charge” has the meaning set forth in Section 2 of Exhibit K. “SDD Adjustment” means the adjustment, if any, to the Monthly Contract Payment, as determined in accordance with Exhibit K. “SDD Energy Adjustment” has the meaning set forth in Section 1 of Exhibit K. “SEC” means the United States Securities and Exchange Commission, or any successor entity. “Self-Schedule” has the meaning set forth in the CAISO Tariff. “Seller” has the meaning set forth in the Preamble. “Seller’s Day-Ahead Forecast” means the most recently updated Forecast submitted by 5:00 p.m. PPT on the day before the Trading Day. “Seller’s Energy Forecast” means Seller’s most recently updated Forecast submitted in accordance with Exhibit I. “Seller’s Final Energy Forecast” means Seller’s Energy Forecast as may be updated for Forced Outages that occur after the Hour-Ahead Scheduling Deadline, but not for Ambient Outages. “Settlement Agreement” has the meaning set forth in Recital C. “Settlement Effective Date” has the meaning set forth in Recital D. “Settlement Interval” has meaning set forth in the CAISO Tariff. “Settling Parties” has the meaning set forth in Recital B. “SGIA” (i.e., Small Generator Interconnection Agreement) means the form of Interconnection Request (as defined in the CAISO Tariff) pertaining to a Small Generating Facility (as defined in the CAISO Tariff), which is attached to the CAISO Tariff as Appendix T. “Simple Interest Payment” means a dollar amount calculated by multiplying the: (a) Dollar amount on which the Simple Interest Payment is based; by (b) Federal Funds Effective Rate or Interest Rate as applicable; by (c) The result of dividing the number of days in the calculation period by 360.

Exhibit A

Definitions

Page 25

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Site” means the real property on which the Generating Facility is located, as further described in Section 1.02(b) and Exhibit B. “Site Control” means that Seller (a) owns the Site, (b) is the lessee of the Site under a Lease, (c) is the holder of a right-of-way grant or similar instrument with respect to the Site, or (d) is managing partner or other Person authorized to act in all matters relating to the control and Operation of the Site and Generating Facility. “Site Host” means the Person or Persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating Facility. “Site Host Load” means the electric energy and capacity produced by or associated with the Generating Facility that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b). “SLIC” means Scheduling and Logging system for the CAISO. “Station Use” means the electric energy produced by the Generating Facility that is (a) used within the Generating Facility to power the lights, motors, control systems and other electrical loads that are necessary for Operation, and (b) consumed within the Generating Facility’s electric energy distribution system as losses needed to deliver electric energy to the Site Host Load, and (c) consumed within the generator collection system as losses between the generator(s) and the high voltage side of the Generating Facility output transformer(s). “Successor” has the meaning set forth in Section 3.20(b)(iii). “Supply Plan” has the meaning set forth in the CAISO Tariff. “System Emergency” has the meaning set forth in the CAISO Tariff. “Tariff Rule 21” means the interconnection standards of the Transmission Provider for distributed generation adopted by the CPUC in Decisions 00-11-001 and 00-12-037, as modified by the CPUC. “Telemetry System” means a system of electronic components that interconnects the CAISO and the Generating Facility in accordance with the CAISO’s applicable requirements as set forth in Section 3.09. “Term” has the meaning set forth in Section 1.01. “Term End Date” has the meaning set forth in Section 1.01. “Termination Payment” has the meaning set forth in Section 6.03. “Term Start Date” has the meaning set forth in Section 1.01.

Exhibit A

Definitions

Page 26

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Term Year” means a 12-month period beginning on the first day of the Term and each successive 12-month period thereafter. “TOD Period” means the time of delivery period used to calculate the Monthly Contract Payment set forth in Section 4 of Exhibit D. “TOD Period Capacity Payment” means the monthly payment to be calculated and made by Buyer to Seller for Power Product capacity during each TOD Period for the month for which a calculation is being performed, as set forth in Section 3(a) of Exhibit D, in dollars. “TOD Period Energy Payment” means the monthly payment to be calculated and made by Buyer to Seller for the Metered Energy during each TOD Period for the month for which a calculation is being performed, as set forth in Section 2(a) of Exhibit D, in dollars. “TOD Period Energy Price” means the price used to calculate the TOD Period Energy Payment, as set forth in Exhibit S and referenced in Section 2(b) of Exhibit D, in dollars per kWh. “TOU” has the meaning set forth in Section 1 of Exhibit S. “Trade Organizations” means the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, and the Independent Energy Producers Association. “Trading Day” means the day in which Day-Ahead trading occurs in accordance with the WECC Preschedule Calendar (as found on the WECC’s website). “Transmission Curtailment Credit Value” or “TCV” is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, as determined in accordance with Section 3 of Exhibit D-2. “Transmission Provider” means any Person responsible for the interconnection of the Generating Facility with the interconnecting utility’s electrical system or the CAISO Controlled Grid or transmitting the Metered Energy on behalf of Seller from the Generating Facility to the Delivery Point. “Transition EEI Agreement” means that certain Edison Electric Institute Master Power Purchase & Sale Agreement, together with the Cover Sheet, any amendments and annexes thereto (including the Collateral Annex and Paragraph 10 thereto) between Buyer and Seller, dated October 15, 2012. “Transition RA Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (RA Capacity), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement.

Exhibit A

Definitions

Page 27

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

“Transition Tolling Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (Energy Only UC Toll (Kern Pipeline – financially settled gas)), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement. “Uninstructed Deviation GMC Rate” means the administrative grid management charge applied by the CAISO to Uninstructed Deviations (as defined in the CAISO Tariff) using the absolute value for the Uninstructed Deviations by Settlement Interval. “Uninstructed Deviation Penalty” means the penalty set forth in the CAISO Tariff. “Useful Thermal Energy Output” has the meaning set forth in 18 CFR §292.202(h) and modified by the Energy Policy Act of 2005, or any successor thereto. “VOM” has the meaning set forth in Section 1 of Exhibit S. “Web Client” has the meaning set forth in Section 2(a) of Exhibit R. “Web Scheduler” has the meaning set forth in Section 2 of Exhibit E. “WECC” means the Western Electricity Coordinating Council, the regional reliability council for the western United States, northwestern Mexico, and southwestern Canada, or any successor entity. “WREGIS” means the Western Renewable Energy Generation Information System, or any successor thereto. *** End of Exhibit A ***

Exhibit A

Definitions

Page 28

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT B Generating Facility and Site Description 1.

Generating Facility Description. (a)

Generating Unit Features. Each Generating Unit has:

(b)

(i)

One General Electric Frame 7 gas turbine, with a nominal electric capacity rating of 76.56 MW;

(ii)

A bypass exhaust stack for simple cycle operation; and

(iii)

A heat recovery steam generator (HRSG) that is used to turn produced water from the oil field into steam for use in an enhanced oil recovery system.

Interconnection Utility System The Generating Facility has been operating in parallel with SCE’s Transmission System since 1985. The Generating Facility consists of a SCE designed and built 220kV switchyard with connections to the four generating units and to a SCE owned transmission line which transmits power to the SCE owned Magunden substation.

(d)

Measurement of Useful Thermal Energy Output Seller sells useful thermal energy output (steam) to Chevron U.S.A. Inc. for use in its enhanced oil recovery system under a long-term sales agreement. The Generating Facility supplies thermal energy in the form of saturated steam comprised of approximately 75% steam and 25% water. Useful thermal energy is calculated using the measured mass flow through the HRSG, measured feedwater temperature, measured steam pressure, measured steam quality, and the ASME steam tables to calculate BTU content of the steam.

(e)

Control Systems The balance of plant control system is an Emerson Ovation Distributed Control System (DCS) utilizing redundant controllers. The redundant controllers provide greater reliability by allowing continued plant operation with the loss of a control processor. Multiple operator interfaces allow the plant operator to maintain control of the turbine with the loss of an operator interface. Non-critical

Exhibit B

Generating Facility and Site Description

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

equipment may be controlled by individual Programmable Logic Controller’s (PLC) or vendor supplied controllers that interface to the balance of plant DCS. (f)

Generating Unit #2 (i)

Name: Kern River Cogeneration Company Unit #2

(ii)

Location: Bakersfield, California

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 2

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: 77.25 MW.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South

(g)

(ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to maintain visibility and control of the turbine with the loss of an operator interface.

Generating Unit #4 (i)

Name: Kern River Cogeneration Company Unit #4

(ii)

Location: Bakersfield, California

Exhibit B

Generating Facility and Site Description

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 4

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: 77.25 MW.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South

(h)

(ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to maintain visibility and control of the turbine with the loss of an operator interface.

Single-line Diagram

Exhibit B

Generating Facility and Site Description

Page 3

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

  Exhibit B

Generating Facility and Site Description

Page 4

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(i)

Site Plan Drawing

  Exhibit B

Generating Facility and Site Description

Page 5

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

2.

Site Description. (a) Kern River Cogeneration Company Plant Site THAT PORTION OF SECTION 32, TOWNSHIP 28 SOUTH, RANGE 25 EAST, H.D.M., IN THE COUNTY OF KERN. STATE OF CALIFORNIA. DESCRIBED AS FOLLOWS: COMMENCING AT THE NORTHWEST CORNER OF SAID SECTION 32; THENCE SOUTH 00 DEGREES 22 MINUTES 14 SECONDS WEST ALONG THE WEST LINE OF THE NORTHWEST QUARTER OF SAID SECTION 32, A DISTANCE OF 1271.73 FEET; THENCE DEPARTING SAID WEST LINE SOUTH 85 DEGREES 37 MINUTES 46 SECONDS EAST A DISTANCE OF 2219.62 FEET TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION; THENCE (1) N.86 DEG. 36 MIN. 19 SEC E., A DISTANCE OF 88.81 FEET; THENCE (2) N.78 DEG. 25 MIN. 31 SEC E., A DISTANCE OF 36.40 FEET; THENCE (3) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 45.00 FEET; THENCE (4) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 40.00 FEET; THENCE (5) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 120.00 FEET; THENCE (6) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (7) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 13.00 FEET; THENCE (8) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (9) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 8.00 FEET; THENCE (10) N.10 DEG. 44 MIN. 52 SEC E., A DISTANCE OF 171.06 FEET; THENCE (11) N.18 DEG. 37 MIN. 55 SEC W., A DISTANCE OF 230.31 FEET; THENCE (12) N.13 DEG. 49 MIN. 58 SEC E., A DISTANCE OF 48.66 FEET; THENCE (13) N.41 DEG. 14 MIN. 26 SEC E., A DISTANCE OF 50.00 FEET; THENCE (14) N.56 DEG. 04 MIN. 49 SEC E., A DISTANCE OF 48.41 FEET; THENCE (15) N.77 DEG. 21 MIN. 00 SEC E., A DISTANCE OF 51.24 FEET; THENCE (16) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 43.00 FEET; THENCE (17) S.60 DEG. 42 MIN. 03 SEC E., A DISTANCE OF 156.59 FEET; THENCE (18) N.87 DEG. 20 MIN. 32 SEC E., A DISTANCE OF 73.55 FEET; THENCE (19) S.56 DEG. 34 MIN. 29 SEC E., A DISTANCE OF 30.89 FEET; THENCE (20) S.20 DEG. 32 MIN. 03 SEC E., A DISTANCE OF 30.87 FEET; THENCE (21) S.06 DEG. 54 MIN. 55 SEC W., A DISTANCE OF 225.22 FEET; THENCE (22) S.04 DEG. 22 MIN. 14 SEC W., A DISTANCE OF 90.00 FEET;

Exhibit B

Generating Facility and Site Description

Page 6

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

THENCE (23) S.03 DEG. 11 MIN. 03 SEC W., A DISTANCE OF 95.34 FEET; THENCE (24) S.01 DEG. 19 MIN. 04 SEC W., A DISTANCE OF 75.11 FEET; THENCE (25) S.17 DEG. 07 MIN. 51 SEC E., A DISTANCE OF 35.47 FEET; THENCE (26) S.19 DEG. 37 MIN. 32 SEC W., A DISTANCE OF 34.21 FEET; THENCE (27) S.12 DEG. 52 MIN. 15 SEC E., A DISTANCE OF 30.36 FEET; THENCE (28) S.82 DEG. 43 MIN. 07 SEC E., A DISTANCE OF 59.08 FEET; THENCE (29) S.66 DEG. 18 MIN. 47 SEC E., A DISTANCE OF 102.79 FEET; THENCE (30) N.89 DEG. 14 MIN. 33 SEC E., A DISTANCE OF 78.31 FEET; THENCE (31) N.53 DEG. 27 MIN. 22 SEC E., A DISTANCE OF 19.85 FEET; THENCE (32) N.18 DEG. 54 MIN. 18 SEC E., A DISTANCE OF 27.89 FEET; THENCE (33) N.76 DEG. 33 MIN. 06 SEC E., A DISTANCE OF 29.41 FEET; THENCE (34) N.60 DEG. 40 MIN. 50 SEC E., A DISTANCE OF 14.42 FEET; THENCE (35) N.24 DEG. 01 MIN. 28 SEC E., A DISTANCE OF 29.73 FEET; THENCE (36) S.74 DEG. 54 MIN. 59 SEC E., A DISTANCE OF 37.66 FEET; THENCE (37) N.80 DEG. 20 MIN. 04 SEC E., A DISTANCE OF 49.48 FEET; THENCE (38) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 20.00 FEET; THENCE (39) S.55 DEG. 03 MIN. 01 SEC E., A DISTANCE OF 25.55 FEET; THENCE (40) S.30 DEG. 37 MIN. 17 SEC E., A DISTANCE OF 24.41 FEET; THENCE (41) S.03 DEG. 13 MIN. 27 SEC E., A DISTANCE OF 30.27 FEET; THENCE (42) S.16 DEG. 11 MIN. 08 SEC E., A DISTANCE OF 42.27 FEET; THENCE (43) S.37 DEG. 28 MIN. 55 SEC W., A DISTANCE OF 109.84 FEET; THENCE (44) S.00 DEG. 13 MIN. 33 SEC W., A DISTANCE OF 207.54 FEET; THENCE (45) S.61 DEG. 20 MIN. 48 SEC W., A DISTANCE OF 23.85 FEET; THENCE (46) N.79 DEG. 55 MIN. 08 SEC W., A DISTANCE OF 20.10 FEET; THENCE (47) N.50 DEG. 43 MIN. 37 SEC W., A DISTANCE OF 52.43 FEET; THENCE (48) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 80.00 FEET; THENCE (49) S.47 DEG. 58 MIN. 24 SEC W., A DISTANCE OF 58.00 FEET; THENCE (50) S.00 DEG. 38 MIN. 21 SEC W., A DISTANCE OF 46.10 FEET; THENCE (51) S.25 DEG. 29 MIN. 43 SEC W., A DISTANCE OF 47.17 FEET; THENCE (52) S.74 DEG. 02 MIN. 51 SEC W., A DISTANCE OF 57.58 FEET; THENCE (53) S.71 DEG. 32 MIN. 13 SEC W., A DISTANCE OF 20.62 FEET; THENCE (54) N.84 DEG. 29 MIN. 01 SEC W., A DISTANCE OF 50.01 FEET; THENCE (55) S.87 DEG. 51 MIN. 03 SEC W., A DISTANCE OF 70.46 FEET; THENCE (56) S.78 DEG. 15 MIN. 26 SEC W., A DISTANCE OF 46.84 FEET; THENCE (57) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 40.36 FEET; THENCE (58) S.74 DEG. 57 MIN. 33 SEC W., A DISTANCE OF 111.33 FEET;

Exhibit B

Generating Facility and Site Description

Page 7

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

THENCE (59) N.63 DEG. 11 MIN. 37 SEC W., A DISTANCE OF 167.69 FEET; THENCE (60) N.45 DEG. 49 MIN. 26 SEC W., A DISTANCE OF 39.05 FEET; THENCE (61) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 26.91 FEET; THENCE (62) N.04 DEG. 59 MIN. 23 SEC W., A DISTANCE OF 92.23 FEET; THENCE (63) N.07 DEG. 43 MIN. 27 SEC W., A DISTANCE OF 71.59 FEET; THENCE (64) N.19 DEG. 15 MIN. 01 SEC E., A DISTANCE OF 214.18 FEET; THENCE (65) N.07 DEG. 53 MIN. 39 SEC W., A DISTANCE OF 23.54 FEET; THENCE (66) N.35 DEG. 26 MIN. 06 SEC W., A DISTANCE OF 31.24 FEET; THENCE (67) N.63 DEG. 49 MIN. 41 SEC W., A DISTANCE OF 16.16 FEET; THENCE (68) N.81 DEG. 48 MIN. 55 SEC W., A DISTANCE OF 75.17 FEET; THENCE (69) S.86 DEG. 24 MIN. 03 SEC W., A DISTANCE OF 50.49 FEET; THENCE (70) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 34.00 FEET; TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION. (b)

Site Control Seller has legal control of the Site under a 1984 Ground Lease from Chevron U.S.A. (CUSA), as amended in 1985 and 2005. Seller also has easement agreements with CUSA providing for ingress and egress to the Site and all other necessary rights-ofway for operation of Seller.

(c)

Site Map

Exhibit B

Generating Facility and Site Description

Page 8

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

*** End of Exhibit B ***

Exhibit B

Generating Facility and Site Description

Page 9

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT C [Intentionally omitted.]

*** End of Exhibit C ***

Exhibit C

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT D Monthly Contract Payment Calculation

1.

Introduction. Each Monthly Contract Payment is calculated on a calendar month basis as follows: MONTHLY CONTRACT PAYMENT, in dollars = TOD Period Energy Payment 1st TOD Period TOD Period Energy Payment 2nd TOD Period TOD Period Energy Payment 3rd TOD Period TOD Period Energy Payment 4th TOD Period TOD Period Capacity Payment 1st TOD Period TOD Period Capacity Payment 2nd TOD Period TOD Period Capacity Payment 3rd TOD Period TOD Period Capacity Payment 4th TOD Period

+ + + + + + +

All TOD Period Energy Payments shall be calculated as set forth in Section 2 of this Exhibit D. All TOD Period Capacity Payments shall be calculated as set forth in Section 3 of this Exhibit D. The “1st TOD Period,” “2nd TOD Period,” “3rd TOD Period” and “4th TOD Period” subscripts refer to the four TOD Periods that apply for the calculation month, as set forth in Section 4 of this Exhibit D. 2.

TOD Period Energy Payment Calculation. (a)

Each monthly TOD Period Energy Payment is calculated as follows: LastHour

TOD PERIOD ENERGY PAYMENT, in dollars =



[(EP-LA) x APE +

FirstHour

LA x MA] Where: EP

= TOD Period Energy Price, stated in Section 2(b) of this Exhibit D, in dollars per kWh.

APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D.

Exhibit D

Monthly Contract Payment Calculation

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D. LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. MA = Metered Amounts for each hour of the applicable TOD Period, in kWh. Metered Amounts for any hour is equal to the sum of Metered Amounts for all Metering Intervals in that hour. First Hour = First hour of the applicable TOD Period. Last Hour = Last hour of the applicable TOD Period. Once 120% of the Expected Term Year Net Energy Production is achieved, no further electric energy payments will be calculated for the remaining TOD Periods within any remaining months of the current Term Year. (b)

Factor “EP” in Section 2(a) of this Exhibit D. The TOD Period Energy Price, in dollars per kWh, for any TOD Period shall be calculated pursuant to and as determined by the methodology set forth in Exhibit S.

(c)

Factor “APE” in Section 2(a) of this Exhibit D. The Allowed Payment Energy for each hour of each TOD Period of any month is calculated as follows: APE = The sum of the Metered Energy when Buyer is Scheduling Coordinator or Scheduled Amounts when Buyer is not Scheduling Coordinator from the Generating Facility for each hour of the TOD Period, in kWh.

3.

TOD Period Capacity Payment Calculation. (a)

Each monthly TOD Period Capacity Payment is calculated on a calendar month basis as follows: TOD PERIOD CAPACITY PAYMENT in dollars = (ACP + FCP) x CAF Where: ACP =

As-Available Capacity Payment for the TOD Period, as determined in accordance with Section 3(b) of this Exhibit D, in dollars per year.

FCP =

Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(g) of this Exhibit D, in dollars per year.

CAF =

The CPUC approved Capacity Payment Allocation Factor for the TOD Period in the year, based upon the formula adopted by the CPUC in D.01-03-067:

Exhibit D

Monthly Contract Payment Calculation

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Season Summer

Winter

(b)

Capacity Payment Allocation Factors TOD Period On-Peak Period Mid-Peak Off-Peak Mid-Peak Off-Peak Super-Off-Peak

Factor 0.1792 0.0310 0.0006 0.0178 0.0011 0.0007

Factor “ACP” in Section 3(a) of this Exhibit D. The As-Available Capacity Payment shall be calculated pursuant to the following formula: AS-AVAILABLE CAPACITY PAYMENT, in dollars = AAC x AACP Where: AAC = As-Available Capacity for the TOD Period, as determined in accordance with Section 3(c) of this Exhibit D, in kWh per hour. AACP= The As-Available Capacity Price adopted by the CPUC in the Decision for the applicable year as set forth in the following table: Year 2012 2013 2014 2015

(c)

As-Available Capacity Price Price $/kW-yr 43.09 45.00 46.97 48.98

Factor “AAC” in Section 3(b) of this Exhibit D. The As-Available Capacity for each TOD Period of each month is calculated as follows: AS-AVAILABLE CAPACITY, in kWh per hour = MAC – FCC (but not less than zero) Where: MAC = The Maximum Allowed Capacity for the TOD Period as determined in Section 3(d) in this Exhibit D, in kWh per hour. FCC = The Firm Contract Capacity for all TOD Periods during a month.

(d)

Factor “MAC” in Section 3(c) of this Exhibit D. The Maximum Allowed Capacity for each monthly TOD Period is calculated as follows: MAXIMUM ALLOWED CAPACITY, in kWh per hour

Exhibit D

= LE / PH

Monthly Contract Payment Calculation

Page 3

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Where: LE

= The sum of the Limited TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(e) of this Exhibit D, in kWh.

PH = The total number of hours in the TOD Period (period hours). (e)

Factor “LE” in Section 3(d) of this Exhibit D. The Limited TOD Energy for each TOD Period of any month is calculated as follows: LastHour

LIMITED TOD ENERGY, in kWh =



(E)Hour

FirstHour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour, in kWh; and (ii) Allowed Hourly Energy, as determined in Section 3(f) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (f)

Factor “E” in Section 3(e) of this Exhibit D. The Allowed Hourly Energy is calculated as follows: ALLOWED HOURLY ENERGY in kWh

= 1 hour x NCC

Where: NCC = The Net Contract Capacity, as set forth in Section 1.02(d), in kW. (g)

Factor “FCP” in Section 3(a) of this Exhibit D. Each monthly Firm Capacity Payment is calculated as follows: FIRM CAPACITY PAYMENT in dollars = MFCP x AF Where: MFCP = Maximum Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(h) of this Exhibit D, in dollars.

Exhibit D

Monthly Contract Payment Calculation

Page 4

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

AF

= (i) (ii)

One (1), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is greater than or equal to 95%; or Zero (0), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is less than 60%; or

(iii) If neither (i) nor (ii) are true, then AF is the Availability Penalty Factor, as calculated in Section 3(n) of this Exhibit D. (h)

Factor “MFCP” in Section 3(g) of this Exhibit D. The Maximum Firm Capacity Payment for each TOD Period of each month is calculated as follows: MAXIMUM FIRM CAPACITY PAYMENT, in dollars = FCC x CP Where: FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d), in kWh per hour. CP

(i)

= Firm Capacity Price, as set forth in Section 1.06(a), in $/kW-year.

Factor “ACF” in Section 3(g) of this Exhibit D. The Availability Credit Factor for each monthly TOD Period is calculated as follows: AVAILABILITY CREDIT FACTOR

= (ECH + CCH) / PH

Where: ECH = The total number of Earned Capacity Hours, determined in accordance with Section 3(j) of this Exhibit D. CCH = The total number of Capacity Credit Hours, determined in accordance with Section 3(m) of this Exhibit D. PH = The total number of hours in the TOD Period (period hours). (j)

Factor “ECH” in Section 3(i) of this Exhibit D. The Earned Capacity Hours for each monthly TOD Period is calculated as follows: EARNED CAPACITY HOURS

=

FE / FCC

Where: FE

= The sum of the Firm TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(k) of this Exhibit D, in kWh.

Exhibit D

Monthly Contract Payment Calculation

Page 5

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d) in kWh per hour. (k)

Factor “FE” in Section 3(j) of this Exhibit D. The Firm TOD Energy for each TOD Period of any month is calculated as follows: LastHour

FIRM TOD ENERGY in kWh



=

(E)Hour

FirstHour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour in kWh; and (ii) Allowed Firm Energy, as determined in Section 3(l) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (l)

Factor “E” in Section 3(k) of this Exhibit D. The Allowed Firm Energy is calculated as follows: ALLOWED FIRM ENERGY in kWh

= 1 hour x FCC

Where: FCC = The Firm Contract Capacity set forth in Section 1.02(d). (m)

Factor “CCH” in Section 3(i) of this Exhibit D. The total number of Capacity Credit Hours for each monthly TOD Period is determined as follows: CAPACITY CREDIT HOURS

= TCV + FCV + MCV

Where: TCV = The total Transmission Curtailment Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-2, when the Metered Energy was curtailed by either the CAISO or the Transmission Provider. FCV = The total Force Majeure Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-1, when the

Exhibit D

Monthly Contract Payment Calculation

Page 6

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Metered Energy was curtailed by a Force Majeure event claimed by Buyer to the extent the Generating Facility is otherwise available. MCV = The total Maintenance Credit Value during the TOD Period, determined in accordance with Section 9 of Exhibit E. (n)

Factor “APF” in Section 3(g) of this Exhibit D. The Availability Penalty Factor for each monthly TOD Period is calculated as follows: AVAILABILITY PENALTY FACTOR = 1.0 – 2.0 x (CR – ACF) Where: APF = The greater of: (i) zero; and (ii) the result of the above equation for APF. CR = 95%, the minimum Capacity Performance Requirement. ACF = The Availability Credit Factor determined in accordance with Section 3(i) of this Exhibit D.

4.

Time of Delivery Periods. TOD Period On-Peak

Summer Jun 1st – Sep 30th Noon – 6:00 p.m.

Winter Oct 1st – May 31st Not Applicable.

8:00 a.m. – Noon

Applicable Days Weekdays except Holidays. Weekdays except Holidays.

Mid-Peak

8:00 a.m. - 9:00 p.m. 6:00 p.m. – 11:00 p.m.

Weekdays except Holidays. 6:00 a.m. – 8:00 a.m.

Weekdays except Holidays.

9:00 p.m. – Midnight

Weekdays except Holidays.

Midnight – Midnight

6:00 a.m. – Midnight

Weekends and Holidays.

Not Applicable.

Midnight – 6:00 a.m.

Weekdays, Weekends and Holidays.

11:00 p.m. – 8:00 a.m. Off-Peak

Super-Off-Peak

“Holiday”, as used in the above table, means New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. When a Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. *** End of Exhibit D ***

Exhibit D

Monthly Contract Payment Calculation

Page 7

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT D-1 Force Majeure Credit Value 1.

Overview. This Exhibit D-1 describes the methodology for computing Force Majeure Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Force Majeure Credit Value. For every period of Force Majeure curtailment requested by Buyer, Buyer shall compute the Force Majeure Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-1, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the Force Majeure event and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of Benchmark Capacity minus Hourly Power Output or zero In case of division by zero, the value being calculated shall be zero.

Exhibit D-1

Force Majeure Credit Value

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Force Majeure Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Force Majeure Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. *** End of Exhibit D-1 ***

Exhibit D-1

Force Majeure Credit Value

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT D-2 Transmission Curtailment Credit Value 1.

Overview. This Exhibit D-2 describes the methodology for computing Transmission Curtailment Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Transmission Curtailment Credit Value. For every period of curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, Buyer shall compute the Transmission Curtailment Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-2, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the curtailment notification and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of: Benchmark Capacity minus Hourly Power Output or zero In case of division by zero, the value being calculated shall be zero.

Exhibit D-2

Transmission Curtailment Credit Value

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Transmission Curtailment Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Transmission Curtailment Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. ______________________________________________________________________________ *** End of Exhibit D-2 ***

Exhibit D-2

Transmission Curtailment Credit Value

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT E Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits 1.

Overview. Seller shall follow the protocols established in this Exhibit E for the scheduling of Maintenance Outages and Major Overhauls, and for any subsequent notification that may be required to update a previously scheduled Maintenance Outage or Major Overhaul for which Seller wishes to obtain Maintenance Credit Value. This Exhibit E also describes the methodology for computing Maintenance Credit Value and Maintenance Debit Value.

2.

Notification. Seller shall direct all Maintenance Outage and Major Overhaul notifications to Buyer’s web-based outage scheduling system or an e-mail address designated by Buyer (the “Web Scheduler”) and to the Generation Operations Center, whose URL and telephone number(s) can be found in Exhibit N.

3.

Scheduling. (a)

Seller shall schedule all Maintenance Outages and Major Overhauls with Buyer in advance. Seller’s failure to schedule an unplanned outage in advance is not a default under this Agreement. The notice requirements for Maintenance Outages and Major Overhauls are as follows: Outage Duration Maintenance Outage, Less than 1 day Maintenance Outage, 1 day or more Major Overhaul

(b)

Exhibit E

Minimum Advance Notice 24 Hours 168 Hours 6 Months

Seller shall provide the following information when scheduling a Maintenance Outage or a Major Overhaul via the Web Scheduler: (i)

The identification number set forth on the cover page of this Agreement;

(ii)

Password (supplied by Buyer);

(iii)

Generating Unit Number*;

(iv)

Capacity Credit Period, including: (1)

The date and time when Seller expects the Capacity Credit Period to begin, and

(2)

The date and time when Seller expects the Capacity Credit Period to end.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(v)

“Scheduled Power Offline”**, in kW, is the Hourly Power Output that is expected to be offline during each hour of the outage period, as such may be updated as set forth in this Exhibit E; and

(vi)

Reason for the requested Maintenance Outage or Major Overhaul.

*Unit designation is applicable only when the contract calls for separate tracking of outage allowance for each Generating Unit. **If unit designation is applicable, Seller must provide the expected Scheduled Power Offline of the Generating Unit scheduled for maintenance; otherwise, Seller must provide the expected Scheduled Power Offline of the Generating Facility. 4.

Rescheduling. (a)

A Maintenance Outage and the associated Capacity Credit Period may be rescheduled if Seller’s request to reschedule is received by Buyer no later than 5:00 p.m. PPT on the day before the Maintenance Outage was previously scheduled to begin.

(b)

A Major Overhaul and the associated Capacity Credit Period may be rescheduled provided:

(c) 5.

(i)

The rescheduled Major Overhaul begins six months or more after the first outage notification date and time;

(ii)

The notification to reschedule is made at least one week before the Major Overhaul was previously scheduled to begin; and

(iii)

There is at least a one-month period between the notification to reschedule and the commencement of the rescheduled Major Overhaul.

Maintenance Outages and Major Overhauls may be rescheduled more than once.

Extension. (a)

Seller may extend a Maintenance Outage or a Major Overhaul and the associated Capacity Credit Period by notifying Buyer of the extension no later than 5:00 p.m. PPT on the day before the outage was previously scheduled to end. Seller’s failure to provide such notice, to the extent resulting from unexpected circumstances, is not a default under this Agreement.

(b)

Maintenance Outages and Major Overhauls and the associated Capacity Credit Periods may be extended more than once.

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(c)

For a Maintenance Outage and the associated Capacity Credit Period which is less than 24 hours in duration, the extension cannot result in a total outage duration greater than 23 hours.

6.

Cancellation. If Seller cancels a scheduled Maintenance Outage, Major Overhaul or the associated Capacity Credit Period, a cancellation notice must be received by Buyer no later than 5:00 p.m. PPT on the day before such Maintenance Outage or Major Overhaul was scheduled to begin.

7.

Updating Scheduled Power Offline.

8.

9.

(a)

If a change in the Hourly Power Output is anticipated or occurs during a Maintenance Outage or a Major Overhaul, the Scheduled Power Offline must be updated on a prospective basis as soon as possible via the Web Scheduler. Scheduled Power Offline cannot be updated once the Maintenance Outage or Major Overhaul is over.

(b)

Multiple updates to the Scheduled Power Offline can be submitted if necessary on a prospective basis.

(c)

If a Maintenance Outage or a Major Overhaul is completed ahead of schedule and Seller’s Hourly Power Output has returned to normal output levels earlier than expected, Seller shall advise Buyer of the situation by providing an update to the Scheduled Power Offline as described in Section 7(a) of this Exhibit E.

Restrictions. (a)

Seller shall make reasonable efforts not to schedule a Maintenance Outage or Major Overhaul during the Peak Months. Should an outage be required during the said period, Seller shall abide by the limit as set forth in Section 1.05(d) for minor maintenance work during peak months.

(b)

Each Capacity Credit Period must be scheduled to start and stop at the beginning of an hour. Also, when scheduling an outage, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

(c)

Seller may not schedule a Maintenance Outage or a Major Overhaul that overlaps another Maintenance Outage, Major Overhaul, or Curtailment Period already scheduled on the Generating Facility. If unit designation is applicable in Section 3(b)(iii) of this Exhibit E, this restriction applies to the Generating Unit.

Maintenance Credit Calculation. For every properly scheduled Maintenance Outage and Major Overhaul, to the extent there is an associated Capacity Credit Period, Buyer shall

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 3

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

compute and apply the associated Maintenance Credit Value and the Maintenance Debit Value following these steps: (a)

A Benchmark Capacity shall be determined for every scheduled Maintenance Outage and Major Overhaul. For purposes of this Exhibit E, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, at or after the time of outage notification, and before the start of the outage. If the outage is rescheduled, the most recent notification time shall be used in defining Benchmark Capacity. If the outage is extended, or its Scheduled Power Offline is updated, the original notification time shall be used in defining Benchmark Capacity, unless the outage has been rescheduled before the extension, in which case the most recent rescheduling notification time shall be used in defining Benchmark Capacity. In the special case of a less-than-one-day Maintenance Outage that directly follows another less-than-one-day Maintenance Outage, Benchmark Capacity of the outage that follows is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, between these two outage time periods. In the event of back-to-back, less-than-one-day Maintenance Outages, Benchmark Capacity for the second outage shall be zero. Notwithstanding this Section 9(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Capacity Credit Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during such Capacity Credit Period.

(b)

For each hour in the Capacity Credit Period of the Maintenance Outage or the Major Overhaul, an Hourly Credit Value and Hourly Debit Value shall be calculated using following formulas: (i)

Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the lesser of Benchmark Capacity minus Hourly Power Output, or Scheduled Power Offline. However, in all cases, Delta shall never be less than zero.

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 4

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(ii)

Hourly Debit Value = (Scheduled Power Offline / Firm Contract Capacity) * 1 hour

(c)

For each hour in the Capacity Credit Period, the Hourly Credit Value shall be applied as Maintenance Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Capacity Credit Period have been applied, or until the condition described in Section 9(d) of this Exhibit E is met, whichever comes first.

(d)

Simultaneous to Section 9(c) of this Exhibit E, for each hour in the Capacity Credit Period, the Hourly Debit Value shall be accumulated as Maintenance Debit Value in a Term-Year-to-date account whose increasing total is to be compared to the appropriate limit set forth in Sections 1.05(a) or (b). Once the Term-Year-todate total reaches or exceeds the limit, no more Hourly Credit Values shall be applied.

(e)

After all the Hourly Credit Values have been applied and the Hourly Debit Values accounted for, the final monthly Maintenance Credit Value and the Term-Year-todate cumulative Maintenance Debit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision.

The above description of the evaluation process assumes that the outage was properly scheduled with sufficient advance notice pursuant to this Exhibit E and was approved by Buyer (or the CAISO, if applicable). Any deviation from the proper scheduling protocol can result in reduced Maintenance Credit Value or increased Maintenance Debit Value. *** End of Exhibit E ***

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 5

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT F [Intentionally omitted.] *** End of Exhibit F ***

Exhibit F

[Intentionally omitted.] Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT G Scheduling Coordinator Services This Exhibit G is only applicable when Buyer is Scheduling Coordinator. 1.

2.

Designation of Buyer as Scheduling Coordinator. (a)

At least 30 days before the Term Start Date, Seller shall take all actions and execute and deliver to Buyer and the CAISO all documents necessary to authorize or designate Buyer as Scheduling Coordinator with the CAISO effective as of the Term Start Date.

(b)

During the Term, unless Seller terminates Buyer as Scheduling Coordinator in accordance with Section 7 of this Exhibit G, Seller may not authorize or designate any other party to act as Scheduling Coordinator, nor shall Seller perform for its own benefit the duties of Scheduling Coordinator, and Seller may not revoke Buyer’s authorization to act as Scheduling Coordinator unless agreed to by Buyer.

(c)

Buyer shall submit bids and schedules to the CAISO in accordance with the CAISO Tariff and Seller’s QF PGA or PGA, as applicable.

(d)

Buyer shall submit all required notices and updates regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO in accordance with the CAISO procedures.

(e)

Seller is not entitled to any Monthly Capacity Payment until Buyer is fully authorized as Scheduling Coordinator for the Generating Facility; provided, however, that Buyer may not take, or not refrain from taking, any action if the result would be to delay such authorization.

Buyer’s Scheduling Responsibilities. Pursuant to the CAISO Tariff, Buyer shall be responsible for the following: (a)

Using the Forecast submitted by Seller to Buyer pursuant to Exhibit I, including updated Forecasts to the extent reasonably practicable, to forecast Seller’s expected generation using Buyer’s forecasting model (“Buyer Projected Energy Forecast”) in any given hour;

(b)

Adjusting Buyer Projected Energy Forecast for forecasted electric energy line losses in accordance with the amount of electric energy Seller is expected to deliver to the Delivery Point;

(c)

Submitting the adjusted Forecasts to the CAISO as Scheduling Coordinator Schedules (as defined in the CAISO Tariff); and

Exhibit G

Scheduling Coordinator Services

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(d)

Receiving notification of the final schedules from the CAISO.

3.

Notices. As Scheduling Coordinator, Buyer shall submit all notices and updates required under the CAISO Tariff and Applicable Laws regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO, including all SLIC Outage requests, SLIC Forced Outages, CAISO Forced Outage Reports, or must offer waiver forms.

4.

Scheduling Fees. In accordance with Section 4.02, Buyer shall invoice to Seller and Seller shall pay to Buyer the following Scheduling Fees: (a)

SC Set-Up Fee. The SC Set-Up Fee is equal to the costs Buyer incurs as a result of the Generating Units or the Generating Facility registration, as applicable, as well as installation, configuration, and testing of all equipment and software necessary, in Buyer’s sole discretion, to Schedule the Generating Unit or the Generating Facility, as applicable, in accordance with the CAISO Tariff. Buyer’s invoice to Seller shall provide a detailed accounting of all costs and charges encompassed in the SC Set-Up Fee, including separate line items for registration charges, equipment costs, software costs, and labor costs (including hourly rate if applicable) itemized for registration, equipment installation, configuration, testing and software related charges. Buyer estimates that the SC Set-up Fee for this Agreement will equal $1,450.

(b)

Monthly Scheduling Fee. The Monthly Scheduling Fee will be as forth in the following table.

Net Contract Capacity (kW)

Monthly Scheduling Fee

Less than 10,000

$2,500

10,000 – 100,000

$5,000

Greater than 100,000

$7,500

5. CAISO Settlements. As Scheduling Coordinator, Buyer shall be responsible for all settlement functions with the CAISO related to the Generating Units or the Generating Facility, as applicable. Seller shall cooperate with Buyer in Buyer’s performance of any settlement functions, and Seller shall promptly deliver to Buyer, or provide Buyer access to, all Generating Unit or the Generating Facility, as applicable, data necessary for CAISO settlements and any correspondence or communications with CAISO related to the Generating Units or the Generating Facility, as applicable, including any invoices or settlement data, in the mutually agreed upon format reasonably requested by Buyer.

Exhibit G

Scheduling Coordinator Services

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Buyer shall render a separate invoice to Seller for all CAISO Charges for which Seller is responsible under this Agreement (“CAISO Charges Invoice”) as described in Sections 1 through 4 of Exhibit J, in accordance with the applicable billing and payment methodologies utilized for the specific CAISO Charge as set forth in the CAISO Tariff. CAISO Charges Invoices shall be rendered after final settlement information becomes available from the CAISO that identifies any CAISO Charges. At Seller’s request, Buyer shall provide Seller with an invoice detailing all Generating Facility CAISO Charges by individual CAISO Charge codes or types used by CAISO to identify individual CAISO Charges including a copy of all supplemental or supporting documentation provided by the CAISO to Buyer in the settlement process. Seller shall pay the amount of CAISO Charges Invoices on or before the later of the 20th day of each month, or tenth day after receipt of the CAISO Charges Invoice or, if such day is not a Business Day, then on the next Business Day. If Seller fails to pay a CAISO Charges Invoice within such timeframe, Buyer may offset any amounts owing to it for these CAISO Charges Invoices as set forth in Section 4.02. 6.

Disputes and Adjustments of CAISO Invoices. The Parties agree that all CAISO Charges Invoices are subject to the CAISO Tariff and may be adjusted by the CAISO, or disputed by Buyer, as Scheduling Coordinator, in accordance with the CAISO Tariff. The Parties agree that all CAISO Charges Invoices are subject to dispute between the Parties in accordance with this Agreement. Notwithstanding anything to the contrary contained in this Agreement, the Parties agree that the obligations under this Exhibit G with respect to the payment of CAISO Charges Invoices, or the adjustment of such CAISO Charges Invoices, shall survive the expiration or termination of this Agreement for a period of 365 days beyond the time period which CAISO may adjust, modify or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the CAISO Tariff.

7.

Terminating Buyer’s Designation as Scheduling Coordinator. (a)

Seller may terminate Buyer as Scheduling Coordinator: (i)

In accordance with Section 7(b) of this Exhibit G; or

(ii)

If Buyer materially fails to fulfill its obligations as Scheduling Coordinator and: (1)

Seller provides advance Notice to Buyer setting forth in reasonable detail the nature of such failure and such failure is not remedied within 30 days after such Notice; provided, however, that if such failure is not reasonably capable of being remedied within such 30day period, Buyer shall have such additional time (not to exceed 120 days) as is reasonably necessary to remedy such failure, so

Exhibit G

Scheduling Coordinator Services

Page 3

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

long as Buyer promptly commences and diligently pursues such remedy;

(iii)

(b)

(2)

Seller (A) submits to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the date of Buyer’s termination as Scheduling Coordinator, and (B) causes its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

(3)

The Parties will take any other action necessary to terminate the designation of Buyer as Scheduling Coordinator, including amending this Agreement; or

If Seller is required to elect Buyer as Scheduling Coordinator in accordance with Section 1.08, then, subject to Section 3.06(b) or 3.09(b), as applicable, by (1) providing a Notice to Buyer on or before the 60th day after Seller meets the requirements of Section 3.06(a) and 3.09(a), and (2) at least 30 days before the replacement Buyer as the Scheduling Coordinator, complying with the requirements for designating a different Scheduling Coordinator by taking all necessary actions to terminate the designation of Buyer as Scheduling Coordinator, including those actions set forth in Sections 7(b)(i) and (b)(ii) of this Exhibit G. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator.

At least 30 days before the expiration of the Term or as soon as an Early Termination Date is declared (regardless of which Party declared it), the Parties will take all actions necessary to terminate the designation of Buyer as Scheduling Coordinator as of 11:59 p.m. PPT on the Term End Date (“SC Replacement Date”). Such actions include the following: (i)

(ii)

Seller shall: (1)

Submit to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the SC Replacement Date; and

(2)

Cause its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

Buyer shall submit a letter to the CAISO resigning as Scheduling Coordinator effective as of the SC Replacement Date.

Exhibit G

Scheduling Coordinator Services

Page 4

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(c)

Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator. *** End of Exhibit G ***

Exhibit G

Scheduling Coordinator Services

Page 5

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT H [Intentionally omitted.] *** End of Exhibit H ***

Exhibit H

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT I Seller’s Forecasting Submittal and Accuracy Requirements 1.

2.

General Requirements. The Parties shall abide by the Forecasting requirements and procedures described below and shall agree upon reasonable changes to these requirements and procedures from time to time as necessary to: (a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the Operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated Forecast and outage submissions.

Seller’s Forecasting Submittal Requirements for all Generating Facilities. (a)

30-Day Forecast. No later than 30 days before the Term Start Date, Seller shall provide Buyer with a Forecast for the 30-day period commencing on the start of the Term using the Web Client. If the Web Client becomes unavailable, Seller shall provide Buyer with the Forecast by e-mail or by telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N. The Forecast, and any updated Forecasts provided pursuant to this Section 2, shall:

(b)

Exhibit I

(i)

Not include any anticipated or expected electric energy losses between the CAISO-Approved Meter and the Delivery Point; and

(ii)

Limit hour-to-hour Forecast changes to no less than 250 kWh during any period when the Web Client is unavailable. Seller shall have no restriction on hour-to-hour Forecast changes when the Web Client is available.

Weekly Update to 30-Day Forecast. Commencing on or before 5:00 p.m. PPT of the Wednesday before the first week covered by the Forecast provided pursuant to Section 2(a) of this Exhibit I, and on or before 5:00 p.m. PPT every Wednesday thereafter until the Term End Date, Seller shall update the Forecast for the 30-day period commencing on the Sunday following the weekly Wednesday Forecast update submission. Seller shall use the Web Client, if available, to supply this weekly update or, if the Web Client is not available, Seller shall provide Buyer with the weekly Forecast update by e-mailing or telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N.

Seller’s Forecasting Submittal and Accuracy Requirements

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(c)

Further Update to 30-Day Forecast. As soon as reasonably practicable and commensurate with Seller’s knowledge, Seller shall provide Forecast updates related to Buyer’s Scheduled daily, hourly and real-time deliveries from the Generating Facility for any cause, including changes in Site ambient conditions, a Forced Outage, or a Real-Time Forced Outage, any of which results in a material change to the Generating Facility’s deliveries (whether in part or in whole). This updated Forecast pursuant to this Exhibit I must be submitted to Buyer via the Web Client by no later than: (i)

5:00 p.m. PPT on the day before the Trading Day impacted by the change, if the change is known to Seller at that time;

(ii)

The Hour-Ahead Scheduling Deadline, if the change is known to Seller at that time; or

(iii) If the change is not known to Seller by the timeframes indicated in (i) or (ii) immediately above, no later than 20 minutes after Seller becomes aware of the event which caused the expected electric energy production change. Seller’s updated Forecast must contain the following information: (w) The beginning date and time of the event resulting in the availability of the Generating Facility and expected electric energy production change;

3.

(x)

The expected ending date and time of the event:

(y)

The expected electric energy production, in MWh; and

(z)

Any other information required by the CAISO as communicated to Seller by Buyer.

Seller’s Forecasting Accuracy Requirements. If a (non-zero) Firm Contract Capacity quantity is applicable to this Agreement, then this Section 3 applies to Seller. (a)

Accuracy Metric. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate and report to Seller the monthly mean absolute error (“MAEm”) between Seller’s Day-Ahead Forecasts and the respective daily summations of Metered Energy: Forecast Error MAEm = Total Forecast

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company n

Forecast Error =



| fi – ai |

i

n

Total Forecast =

 fi i

where: n

= the total number of hours in calendar month “m”

i

= an hour within month “m”

fi = Seller’s Day-Ahead Forecast for hour “i” ai = the quantity of (i) Metered Energy for hour “i” plus the quantity of electric energy not delivered as a result of a Real-Time Forced Outage for hour “i” (in MWh) when the Generating Facility is not PIRP-eligible, or when Buyer is not Scheduling Coordinator; or (ii) the actual available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator. Buyer shall report each MAEm to Seller and, upon Seller’s request, Buyer shall furnish all supporting calculations within a reasonable timeframe. Notwithstanding anything to the contrary set forth in this Section 3(a), for hour “i” for which the absolute difference between variable “fi” and variable “ai” is a number greater than zero, to the extent that such difference results from the fault or negligence of Buyer in its role as Scheduling Coordinator the value “| fi – ai |” for that hour shall be deemed to be zero. (b) Forecasting Penalty. If the MAEm for a particular month “m” is greater than 15% or if the average Forecast error for all hours of the month is greater than three MW, then an “MAE Failure” will be deemed to have occurred. An MAE Failure will be waived if Seller demonstrates to Buyer’s reasonable satisfaction that the MAE Failure was the result of unexpected changes in either electrical or steam demand associated with the Site Host Load. If such MAE Failure has been waived, then that month does not count as a month in which there was an MAE Failure. For each month in which an MAE Failure has occurred, Seller shall pay a fee equal to the applicable Monthly Scheduling Fee in addition to any otherwise applicable Monthly Scheduling Fee. During each month an MAE Failure occurs, subject to the limitations of the following paragraph, Seller will continue to receive Monthly Capacity Payments for the Firm Contract Capacity based on the Firm Capacity Price and capacity payment calculations for firm capacity as set forth in Section 3 of Exhibit D.

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 3

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

If, however, an MAE Failure occurs three times in any rolling 12-month period, then starting on the first day of the calendar month immediately following the third such occurrence (such month, the “First Penalty Month”): (i)

The quantity of Firm Contract Capacity specified in Section 1.02(d) will be deemed to be zero (“Penalized Firm Contract Capacity”); and

(ii)

The quantity of As-Available Contract Capacity specified in Section 1.02(d) will be deemed increased by the quantity of Firm Contract Capacity as such quantity existed before the First Penalty Month (“Penalized As-Available Contract Capacity”).

The Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall continue to be in effect during every subsequent calendar month until there are two consecutive calendar months without an MAE Failure (including a month in which an MAE Failure has been waived). Upon such event, starting on the first day of the calendar month immediately following the second consecutive month during which Buyer does not have an MAE Failure, the Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall revert to the Firm Contract Capacity and AsAvailable Contract Capacity quantities existing before the First Penalty Month. *** End of Exhibit I ***

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 4

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT J CAISO Charges If at any time after the Term Start Date Buyer is not Scheduling Coordinator for the Generating Facility, then Buyer will not be responsible for any CAISO Charges. If at any time after the Term Start Date Buyer is Scheduling Coordinator for the Generating Facility, then Buyer shall pay all CAISO Charges and receive all CAISO Revenues; provided, however, if at any time after the Term Start Date: 1.

The CAISO implements or has implemented any sanction or penalty related to Scheduling, outage reporting or generator Operation, and any such sanctions or penalties are imposed on the Generating Facility or to Buyer as Scheduling Coordinator for the Generating Facility due solely to the actions or inactions of Seller, then such sanctions or penalties will be Seller’s responsibility;

2.

Seller or any third party dispatches any portion of the Net Contract Capacity for the benefit of any party other than Buyer or a Site host in respect of the Host Site, then Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator);

3.

Seller does not comply with: (a)

The requirements set forth in Section 3.15; or

(b)

Seller’s obligation associated with any CAISO or Transmission Provider notice or instruction (as may be communicated by Buyer as Scheduling Coordinator) to (i) increase output to the Firm Contract Capacity during a System Emergency or an Emergency Condition, or (ii) reschedule a planned outage set to occur during a System Emergency or an Emergency Condition, then

Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges associated with any failure set forth in Sections 3(a) or 3(b) of this Exhibit J (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator); or 4.

If the Generating Facility is PIRP-eligible and is not certified as a PIRP resource for any reason, then Seller shall indemnify, defend, and hold Buyer harmless against all CAISO Charges associated with the electric energy generated and delivered from the Generating Facility.

If any of Sections 1 through 4 of this Exhibit J apply and the Generating Facility is subject to an Uninstructed Deviation Penalty, Seller will not be required to pay the SDD Energy Adjustment and, instead, shall be responsible for all applicable Uninstructed Deviation Penalty charges for the Generating Facility. *** End of Exhibit J ***

Exhibit J

CASIO Charges

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT K Scheduling and Delivery Deviation Adjustments If Buyer is Scheduling Coordinator for the Generating Facility and if the Generating Facility is not PIRP-eligible, then Seller or Buyer, as the case may be, shall be responsible for the following SDD Adjustments with respect to the Generating Facility: 1.

SDD Energy Adjustment. An Adjustment will be calculated for each Settlement Interval in a month if the Metered Energy is either (a) less than the Performance Tolerance Band Lower Limit in any Settlement Interval or (b) greater than the Performance Tolerance Band Upper Limit in any Settlement Interval. When the SDD Energy Adjustment is negative, Seller shall make a payment to Buyer and when the SDD Energy Adjustment is positive, Seller shall receive a credit from Buyer. The SDD Energy Adjustment is calculated as follows: If A < D, then SDD Energy Adjustment= (D – A) x (EP – P) or If A > E, then SDD Energy Adjustment = (A – E) x (P – EP) Otherwise, the SDD Energy Adjustment = 0 where: A = Metered Energy for the Settlement Interval; B = Seller’s Final Energy Forecast based on the hourly forecasts made pursuant to Exhibit I corresponding to the Settlement Interval; C = Performance Tolerance Band = The greater of (a) three percent of the Seller’s Final Energy Forecast divided by the number of Settlement Intervals in such hour or (b) one (1) MWh divided by the number of Settlement Intervals in such hour; D = Performance Tolerance Band Lower Limit = (B – C); E = Performance Tolerance Band Upper Limit = (B + C); EP =

TOD Period Energy Price applicable to the Settlement Interval specified in Section 2(b) of Exhibit D; and

P = Real-Time Price for the Generator’s PNode as published by the CAISO on OASIS for the Settlement Interval.

Exhibit K

Scheduling and Delivery Deviation Adjustments

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

2.

SDD Administrative Charge. Seller shall make a payment to Buyer (the “SDD Administrative Charge”) for each Settlement Interval in a month if Metered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, in any Settlement Interval. The SDD Administrative Charge is calculated as follows: If A > (B + C) or A < (B – C), then: SDD Administrative Charge = (Absolute Value (B – A) – C) x Uninstructed Deviation GMC Rate. Otherwise, the SDD Administrative Charge = 0. *** End of Exhibit K ***

Exhibit K

Scheduling and Delivery Deviation Adjustments

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT L Physical Trade Settlement Amount This Exhibit L is only applicable when Buyer is not Scheduling Coordinator. 1.

Physical Trades Cleared in the IFM. The CAISO Revenue credited to Buyer’s account by CAISO as a result of a Physical Trade having cleared in the IFM shall be for Buyer’s account.

2.

Physical Trades not Cleared in the IFM. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate the Physical Trade Settlement Amount (“PTSAi”) for each hour as follows: PTSAi =

CPTi x (CPTPi – PNodei)

Where: i

=

an hour within month “m”

CPT

=

Converted Physical Trade, in MWh

CPTP

=

Converted Physical Trade Price, and

PNode

=

the Generating Facility’s PNode price, in dollars per MWh.

If the PTSAi is positive and Seller submitted the original Physical Trade in accordance with Section 3.14(s)(ii) and Exhibit I, then Buyer shall owe Seller the PTSAm for month m. In any event the PTSAi is negative, however, then Seller shall owe Buyer the PTSAi. *** End of Exhibit L ***

Exhibit L

Physical Trade Settlement Amount

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT M SC Trade Settlement Amount This Exhibit M is only applicable when Buyer is not Scheduling Coordinator. If, in any Settlement Interval, a Generating Facility’s Scheduled Amount differs from the Generating Facility’s Metered Energy by more than the SC Trade Tolerance Band, then Seller shall be subject to a payment adjustment calculated by Buyer in accordance with the procedures and formulas set forth below. (1)

Under-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy, and the Real-Time Price is greater than the DayAhead Price payable during the Settlement Interval, then Seller’s monthly payment amount shall be reduced by each Under-Scheduling Settlement Interval Adjustment Amount calculated by the following formula: UNDER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [A – B] x [D – C] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No under-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy if, during such Settlement Interval, the Real-Time Price is equal to or less than the Day-Ahead Price payable during the Settlement Interval. (2)

Over-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy, and the Real-Time Price is less than the DayAhead Price payable during the Settlement Interval; Then Seller’s monthly payment amount shall be reduced by each Over-Scheduling Settlement Interval Adjustment Amount calculated by the following formula:

Exhibit M

SC Trade Settlement Amount

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

OVER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [B – A] x [C – D] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No over-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy if, during such Settlement Interval, the Real-Time Price is greater than or equal to the Day-Ahead Price payable during the Settlement Interval. *** End of Exhibit M ***

Exhibit M

SC Trade Settlement Amount

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT N Notice List KERN RIVER COGENERATION COMPANY

SOUTHERN CALIFORNIA EDISON COMPANY

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

Contract Sponsor: Attn: Executive Director Street: P.O. Box 80478 City: Bakersfield, California 93380 Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Reference Numbers: Duns: 17-357-0292 Federal Tax ID Number: 95-3880295

Contract Sponsor: Attn: Vice President of Renewable and Alternative Power Street: 2244 Walnut Grove Avenue City: Rosemead, California 91770 Phone: Facsimile: Reference Numbers: Duns: 006908818 Federal Tax ID Number: 95-1240335

Contract Administration: Attn: Business Manager Phone: (661) 615-4675 Facsimile: (661) 615-4610 E-mail: [email protected]

Contract Administration: Attn: Phone: Facsimile: E-mail:

Forecasting: Attn: Control Room Phone: (661) 615-4639 Facsimile: (661) 615-4623 E-mail: [email protected]

Forecasting: Attn: Phone: 626.307.4420 Facsimile: E-mail: [email protected]

Day-Ahead Forecasting: Phone: (661) 615-4639 Facsimile: (661) 615-4623 E-mail: [email protected]

Day-Ahead Scheduling: Attn: Manager of Day-Ahead Operations Attn: Scheduling Desk Phone: 626.307.4425 or 626.307.4420 Facsimile: 626.307.4413 E-mail: [email protected] Real-Time Scheduling: Attn: Manager of Real-Time Operations Attn: Operations Desk Phone: 626.307.4405 or 626.307.4453 Facsimile: 626.307.4416 E-mail: [email protected]

Real-Time Forecasting: Phone: (661) 615-4639 Facsimile: (661) 615-4623 E-mail: [email protected]

Exhibit N

Notice List

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Payment Statements: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] CAISO Charges and CAISO Sanctions: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Payments: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Wire Transfer: BNK: Chase Manhattan ABA: 021-0000-21 ACCT: 910-2588-697 Credit and Collections: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Guarantor: N/A Attn: Phone: Facsimile: E-mail: Lender: N/A Attn: Phone: Facsimile: E-mail:

Payment Statements: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: CAISO Charges and CAISO Sanctions: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Payments: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Wire Transfer: BNK: JP Morgan Chase Bank ABA: 021000021 ACCT: 323-394434 Credit and Collateral: Attn: Manager of Credit and Collateral Phone: Facsimile: Email: With additional Notices of an Event of Default or Potential Event of Default to: Attn: Manager SCE Law Department Power Procurement Section Phone: Facsimile: Email: Guarantor: N/A Attn: Phone: Facsimile: E-mail: Lender: N/A Attn: Phone: Facsimile: E-mail:

*** End of Exhibit N ***

Exhibit N

Notice List

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT O [Intentionally omitted.] *** End of Exhibit O ***

Exhibit O

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT P [Intentionally omitted.] *** End of Exhibit P ***

Exhibit P

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT Q [Intentionally omitted.] *** End of Exhibit Q ***

Exhibit Q

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT R Outage Schedule Submittal Requirements 1.

General Requirements. The Parties shall abide by the Outage Schedule Submittal Requirements described below and shall agree upon reasonable changes to these requirements and procedures from time to time, as necessary to:

2.

(a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated forecast and outage submissions.

Seller’s Availability Forecasting Submittal Requirements for all Generating Facilities. Seller shall submit maintenance and planned outage schedules in accordance with the following schedule: (a)

No later than January 1st, April 1st, July 1st and October 1st of each Term Year, and at least 60 days before the Term Start Date, Seller shall submit to Buyer its schedule of proposed planned outages (“Outage Schedule”) for the subsequent twenty four-month period using a Buyer-provided web-based system or an e-mail address designated by Buyer (“Web Client”).

(b)

Seller shall provide the following information for each proposed planned outage: (i)

Start date and time;

(ii)

End date and time; and

(iii)

Capacity online, in MW, during the planned outage.

(c)

Within 20 Business Days after Buyer’s receipt of an Outage Schedule, Buyer shall notify Seller in writing of any request for changes to the Outage Schedule, and Seller shall, consistent with Prudent Electrical Practices, accommodate Buyer’s requests regarding the timing of any planned outage.

(d)

Seller shall cooperate with Buyer to arrange and coordinate all Outage Schedules with the CAISO.

Exhibit R

Outage Schedule Submittal Requirements

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(e)

In the event a condition occurs at the Generating Facility which causes Seller to revise its planned outages, Seller shall provide Notice to Buyer, using the Web Client, of such change (including, an estimate of the length of such planned outage) as required in the CAISO Tariff after the condition causing the change becomes known to Seller.

(f)

Seller shall promptly prepare and provide to Buyer upon request, using the Web Client, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code, the CAISO Tariff or any Applicable Law mandating the reporting by investor owned utilities of expected or experienced outages by electric energy generating facilities under contract to supply electric energy. *** End of Exhibit R ***

Exhibit R

Outage Schedule Submittal Requirements

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT S TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements Introduction. Subject to Section 4.04 and Exhibit D, this Exhibit S sets forth the formulas and methodology that Buyer will use in order to calculate the TOD Period Energy Price, and also sets forth Seller’s Greenhouse Gas emissions reporting requirements. 1. TOD Period Energy Price. Subject to Section 2 of this Exhibit S, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable time-period in accordance with the following formula: TOD Period Energy Price $/kWh = ((Applicable HR * BTGP/1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = The Heat Rate for the specified time-period, per the following table: Calendar Year(s) 2011 2012 January 1, 2013 through December 31, 2014 January 1, 2015 until the termination of this Agreement

Heat Rate (Btu/kWh) 8,700 8,225 8,125 Market Heat Rate

BTGP = Calendar month Burner Tip Gas Price ($/MMBtu), per the Decision and CPUC Resolution E-4246; VOM = Calendar month avoided variable O&M ($/kWh), per the Decision and CPUC Resolution E-4246; GHG Charges = All taxes, charges or fees assessed with the implementation and regulation of Greenhouse Gas emissions with respect to the Generating Facility imposed by any Governmental Authority, such as the CARB’s AB 32 Cost of Implementation Fee (as defined in Title 17 C.C.R. §95200). For example, if the charges are assessed on but not included in fuel consumption or gas costs, the Applicable HR or Burner Tip Gas Price will be used to derive the dollars per kilowatt-hour charge. On January 1, 2015 or the commencement of the First Compliance Period, the GHG Charges will equal zero in the above formula; TOU (i.e., time-of-use) = Throughout the Term, the applicable time-of-use factors are as follows:

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

On-Peak Mid-Peak Off-Peak Super Off-Peak

Summer 1.4251 see below 0.8526 N/A

Winter N/A 1.2185 see below 0.7760

Summer Mid-Peak = (Total # hours in month - (1.4251 * # of Summer On-Peak hours in month) - (0.8526 * # of Summer Off-Peak hours in month)) / # of Summer Mid-Peak hours in month Winter Off-Peak = (Total # hours in month - (1.2185 * # of Winter Mid-Peak hours in month) - (0.7760 * # of Winter Super Off Peak hours in month)) / # of Winter Off-Peak hours in month LA (i.e., hourly location adjustment, in $/kWh) = LMPQF - LMPTrading Hub Where the hourly location adjustment (i.e., LA) will be based on the hourly Day-Ahead prices and actual hourly generation by the Generating Facility for delivery to Buyer as follows: LMPQF (in $/kWh) = The hourly Day-Ahead Locational Marginal Price at the point of interconnection with the CAISO Controlled Grid associated with the Generating Facility; and LMPTrading Hub (in $/kWh) = The hourly Day-Ahead Locational Marginal Price of the trading hub where the Generating Facility is located (i.e., SP15 Existing Zone Generation Trading Hub (formerly SP15), NP15 Existing Zone Generation Trading Hub (formerly NP15), or ZP26 Existing Zone Generation Trading Hub (formerly ZP26), as applicable, or any successor thereto). 2. TOD Period Energy Price during the Floor Test Term. (a) If there is a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), then, during the Floor Test Term, the TOD Period Energy Price will be the higher of the following two formulas (the “GHG Floor Test”): (i) TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A;

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 2

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

BTGP ($/MMBtu) = As set forth above; VOM ($/kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. OR (ii) TOD Period Energy Price $/kWh = ((Applicable HR * (BTGP + GHG Allowance Price) /1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = (A) 8,225 Btu/kWh through December 31, 2012; (B) 8,125 Btu/kWh from January 1, 2013 through December 31, 2014; and (C) Actual HR from January 1, 2015 until the end of the Floor Test Term; BTGP ($/MMBtu) = As set forth above; GHG Allowance Price ($/MMBtu) = Allowance Cost ($/MT) * 117lbs of Greenhouse Gas per MMBtu / 2,204.6 lbs per MT Where: Allowance Cost ($/MT) = The cost of one Allowance, determined using the GHG Auction clearing price from the latest GHG Auction that has taken place during the calendar quarter immediately preceding the date that Buyer’s payment is due to Seller; provided, however, that if there is no GHG Auction held during the applicable time-period, then the Allowance Cost is determined in accordance with Section 2(c) of this Exhibit S; VOM ($/kWh) = As set forth above; GHG Charges ($/kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above.

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 3

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

(b) Free Allowance Reporting and Allocation. If, at any time, Buyer makes a monthly payment to Seller utilizing the GHG Floor Test formula set forth in Section 2(a)(ii) of this Exhibit S, then Buyer shall deduct from the monthly payment to Seller for the applicable month the value of the Free Allowances disclosed in and based on all Free Allowance Notices that have not already been applied to a prior payment to Seller; provided, however, that if Buyer, using reasonable efforts, is unable to process such payment adjustment for the applicable month, then Buyer shall make such payment adjustment to the next monthly payment due to Seller. For any month that Buyer utilizes the formula set forth in Section 2(a)(ii) of this Exhibit S to make a monthly payment to Seller, Buyer shall maintain a record of the value and quantity of all Free Allowances disclosed in the Free Allowance Notices, if any, and shall deduct the value of such Free Allowances to any subsequent monthly payment due to Seller where Buyer calculates such monthly payment utilizing the formula set forth in Section (2)(a)(ii) of this Exhibit S until such time that the value of all such Free Allowances are expended. In order for Buyer to make the payment adjustment set forth in the immediately preceding paragraph, Seller agrees to deliver to Buyer, within twenty (20) days of receiving any Free Allowances, a Free Allowance Notice for the applicable month, which Free Allowance Notice must include all Additional GHG Documentation. Buyer shall value any such Free Allowances using the same methodology Buyer uses in valuing the Allowance Cost, as set forth above. (c) Determining Allowance Costs under the GHG Floor Test if there is No GHG Auction. This Section 2(c) is applicable if no GHG Auction has been held during the time-period for which the Allowance Cost variable set forth in Section 2(a) of this Exhibit S is to be determined. In such an instance, publicly available indices will be used to determine the price for the applicable period. If no such indices exist, Buyer will meet with the Trade Organizations to negotiate in good faith to reach an agreement on setting the Allowance Cost variable. If, after negotiating for fifteen (15) Business Days, Buyer and the Trade Organizations have not reached an agreement on setting the Allowance Cost variable, then Buyer and the Trade Organizations shall each select, within fifteen (15) days after such failed negotiations, price quotations for the cost of one Allowance, as set forth in two (2) different Reference Market-Makers, for a total of four (4) price quotations. The Allowance Cost variable for the applicable time-period will be determined by taking the average of the four (4) price quotations so selected by Buyer and the Trade Organizations. Seller agrees and acknowledges that it shall be bound by any agreement as to the Allowance Cost variable between Buyer and the Trade Organizations, in accordance with the foregoing. (d) TOD Period Energy Price from the end of the Floor Test Term. As of end of the Floor Test Term until the termination of this Agreement, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable timeperiod in accordance with the following formula:

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 4

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A; BTGP ($/MMBtu) = As set forth above; VOM ($kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. (e) Seller’s Responsibility. Other than Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges as set forth in payment formulas above, Seller is solely responsible for all GHG Compliance Costs and all other costs associated with implementation and regulation of GHG emissions with respect to Seller or the Generating Facility. 3. Reporting Requirements. (a) From the Effective Date through the Term End Date (and for any period following the termination of this Agreement to the extent relating back to the Term), Seller shall provide to Buyer the following information (together, the “Annual GHG Reports”): (i) On or before the fifth (5th) Business Day following Seller’s timely submission to the CARB (or any other authorized Governmental Authority having jurisdiction in California) of the CARB Mandatory GHG Emissions Annual Report, or such other annual report submitted to the CARB, detailing the Greenhouse Gas emissions of the Generating Facility for the applicable calendar year (as verified by an independent third party, if applicable) (the “CARB Annual Report”), Seller shall deliver such CARB Annual Report to Buyer; and (ii) To the extent not set forth in the CARB Annual Report (or if Seller is no longer required to submit the CARB Annual Report for any reason), then Seller shall submit to Buyer, along with the CARB Annual Report (or, if Seller is no longer required to submit the CARB Annual Report for any reason, then on the sixtieth (60th) Business Day following the end of the applicable calendar year), the following information for the applicable calendar year, which, in each case, must be verifiable and of settlement quality: (1) the Useful Thermal Energy Output of the Generating Facility; and (2)

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 5

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

total fuel usage of the Generating Facility; and (3) the total amount of Greenhouse Gas emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, and the Useful Thermal Energy Output of the Generating Facility; and (4) the total electric energy produced by the Generating Facility, the electric energy used to serve the Site Host Load, and the electric energy delivered to Buyer; and (5) the number of Allowances (including Free Allowances) held or surrendered by Seller for such calendar year during any period where the TOD Period Energy Price is calculated based on the GHG Floor Test. (b) If Buyer requires any other information not delineated in Section 3(a) of this Exhibit S in order to comply with any Greenhouse Gas emissions reporting requirements adopted by the CARB or by any other Governmental Authority and imposed on Buyer (other than the information that Seller must provide in accordance with Section 3(c) of this Exhibit S), then Buyer shall promptly meet and confer with the Trade Organizations regarding such other information that Buyer requires and negotiate in good faith to reach a mutually acceptable agreement. Seller agrees and acknowledges that it shall be bound by any agreement between Buyer and the Trade Organizations, in accordance with the foregoing. (c) Buyer will review the Annual GHG Reports described in this Section 3 to determine if there is any discrepancy in the payments made by Buyer to Seller for GHG Compliance Costs during the course of the applicable calendar year. To the extent Buyer determines that there is any such discrepancy, (i) if Buyer owes Seller an additional payment for GHG Compliance Costs, then Buyer shall make such additional payment in a subsequent monthly payment to Seller under this Agreement, or (ii) if Seller owes Buyer a payment refund for GHG Compliance Costs, then Buyer shall offset such payment refund amount in a subsequent monthly payment to Seller under this Agreement. If this Agreement terminates before Buyer is able to make such additional payment for GHG Compliance Costs or offset such GHG Compliance Costs payment refund from Seller’s monthly payments, as applicable, then Buyer or Seller, as applicable, shall pay all remaining payment amounts due within the thirty- (30) day period after the termination of this Agreement. (d) To the extent that the information provided by the disclosing Party in accordance with this Section 3 is Confidential Information, the receiving Party shall treat such Confidential Information with the same degree of care that it currently treats the data and information provided by Qualifying Cogeneration Facilities under the existing Qualifying Cogeneration Facilities monitoring compliance program. 4. Market Disruption Event. Unless this Agreement has terminated, if, on or after the date that the Market Heat Rate applies to and is used in the calculation of the TOD Period Energy Price and until the termination of this Agreement, there occurs a Market Disruption Event, then the Market Heat Rate for the affected Trading Day(s) must be determined by reference to the Market Heat Rate for the first Trading Day thereafter on which no Market Disruption

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 6

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

Event exists; provided, however, that if the Market Heat Rate is not so determined within five (5) Trading Days after the Market Disruption Event occurred or existed, then Buyer shall meet with the Trade Organizations to negotiate in good faith to reach an agreement on a Market Heat Rate (or a method for determining a Market Heat Rate), and if Buyer and the Trade Organizations have not so agreed on or before the twelfth (12th) Trading Day after which the Market Disruption Event occurred or existed, then the Market Heat Rate will be determined in good faith by taking the average of the price quotations for electric energy and relevant Trading Days that are obtained from no more than two (2) Reference Market-Makers selected by each of Buyer and the Trade Organizations (for a total of four (4) price quotations). Seller hereby agrees and acknowledges that it shall be bound by any agreement as to a Market Heat Rate (or a method for determining a Market Heat Rate) between Buyer and the Trade Organizations, in accordance with the foregoing. *** End of Exhibit S ***

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 7

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

EXHIBIT T QF Efficiency Monitoring Program – Cogeneration Data Reporting Form 2244 Walnut Grove Ave, Rosemead, CA 91770 QF Efficiency Monitoring Program Administrator, (626) 302-9110 [email protected] [PrevYear] I.

Name and Address of Project Name: Street: City: ID No.: ________

II. In Operation: Yes

State:

Zip Code:

Generation Nameplate (KW): __________________ No

III. Can your facility dump your thermal output directly to the environment?

Yes

No

IV. Ownership Ownership

Name

Address

(%)

1 2 3 4 5

Utility Y N Y N Y N Y N Y N

V. [PrevYear] Monthly Operating Data 

Indicate the unit of measure used for your useful thermal output if other than mBTUs: BTUs Therms mmBTUs



If Energy Input is natural gas, use the Lower Heating Value (LHV) as supplied by Gas Supplier. Useful Power Output (kWh)

Energy Input (Therms)

Useful Thermal Output (mBtu)

JAN Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yearly Total

Exhibit T Form

QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

Southern California Edison RAP ID #2811, Kern River Cogeneration Company

*** End of Exhibit T ***

Exhibit T Form

QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN KERN RIVER COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY

This confirmation letter and the appendices attached hereto and incorporated herein (“Confirmation”) confirms the Transaction between Kern River Cogeneration Company (“Seller” or “Kern River”) and Southern California Edison Company (“Buyer” or “SCE”) dated as of October 15, 2012 (“Confirmation Effective Date”) regarding the sale and purchase of the Product, as such term is defined below in Section 1.5, in accordance with and subject to the terms and provisions of this Confirmation, the EEI Master Power Purchase & Sale Agreement, together with the Cover Sheet (the “Transition Cover Sheet”), any amendments and annexes thereto between Seller and SCE dated as of October 15, 2012 (“Transition Master Agreement”), and Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement.” Capitalized terms used but not defined in this Confirmation shall have the meanings ascribed to them in the Transition EEI Agreement or the Tariff. If any term in this Agreement conflicts with the Tariff, the definition set forth in this Agreement shall supersede.

RECITALS

A.

Seller owns and operates Generating Unit # 1 and Generating Unit # 3, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement.

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement.

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition RA Confirmation and the Transition PPA.

ARTICLE 1 TRANSACTION DEFINITIONS 1.1

Seller

Kern River Cogeneration Company. 1.2

Buyer

SCE. 1.3

Term

The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied; provided, however, that: (i) before the commencement of the Delivery Period, SCE must have obtained, in its sole discretion or waived, CPUC Approval, and (ii) before the commencement of the Delivery Period, FERC Approval as set forth in the Transition PPA must have been obtained.

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1.4

Delivery Period

The “Delivery Period” commences on the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained; provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition PPA and Transition RA Confirmation have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), and ends June 30, 2015. 1.5

Product

Capacity, Energy, Ancillary Services, and any other product derived from or associated with each Generating Unit including any Green Attributes associated with the Capacity, Energy and Ancillary Services (collectively, the “Product”). During the Delivery Period, Seller shall sell and deliver, and SCE shall purchase and receive, the Product, subject to the terms and conditions of this Confirmation; provided, however, that Seller’s Allowances shall be treated in accordance with Article 20. Seller represents, warrants, and covenants that it will deliver the Product to SCE free and clear of all liens, security interests, claims, and encumbrances. Seller shall not substitute or purchase the Product or any portion of the Product from any other generating resource or from the market for delivery hereunder. 1.6

Energy Delivery Point

The Energy Delivery Point shall be as described and set forth in the single-line diagram of grid interconnection attached hereto as Appendix 1.6. Except as otherwise set forth in this Confirmation, Seller shall be responsible for all charges and penalties associated with the operation of the Generating Units and transmission of Energy up to and including the Energy Delivery Point, and SCE shall be responsible for all charges and penalties associated with receiving and transmitting Energy after and from the Energy Delivery Point. Title, possession, and risk of loss related to Energy shall transfer from Seller to SCE after the Energy Delivery Point. In the event of a failure by Seller to deliver the Product to the Energy Delivery Point, Article Four of the Transition Master Agreement shall not apply. The Energy Delivery Point specified herein is the Product’s “Delivery Point” for this Transaction for purposes of the Transition EEI Agreement. 1.7

Intentionally Deleted

1.8

Generating Units

Each Generating Unit and its applicable description are set forth in Appendix 1.8. 1.9

No Change to Other Agreements

Notwithstanding anything to the contrary in this Confirmation, Seller and SCE each acknowledge and agree that with respect to the Generating Units which are subject to the obligations under the Agreement, the Transition RA Confirmation and the Transition PPA, any other agreement between Seller and SCE, including any interconnection agreement, is separate and apart from the Agreement, the Transition RA Confirmation and the Transition PPA, such that no other agreement shall modify or add to the Parties’ obligations under the Transition EEI Agreement or this Confirmation, and that no Party’s breach under such other agreement shall excuse a Party’s nonperformance under the Agreement, except as otherwise specifically provided for under this Confirmation.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

ARTICLE 2 PURCHASE AND SALE OF PRODUCT 2.1

Exclusivity

During the Delivery Period, SCE shall have the exclusive right to the Product purchased by SCE hereunder, and all benefits derived therefrom, including the exclusive right to use, market, or resell the Product (or any portion thereof) purchased hereunder and the right to all revenues generated from the use, resale, or marketing of such Product, and Seller may not sell, assign, or otherwise transfer, or commit to sell, assign, or otherwise transfer, the Product (or any portion thereof) or any benefits derived therefrom, to any party other than SCE. In addition, SCE shall have the ability to dispatch each Generating Unit to its PMax at the instruction of the CAISO and subject to the Operating Restrictions applicable to such Generating Unit and shall be entitled to all benefits of such dispatch including all revenues associated with such capacity, energy or ancillary services up to and including the Generating Unit’s PMax. 2.2

Ownership

Seller shall maintain ownership of, and exclusive demonstrable rights to each of the Generating Units throughout the Term.

ARTICLE 3 COMPENSATION AND AVAILABILITY 3.1

Compensation (a)

Monthly Capacity Payment: For each Generating Unit, SCE shall make the Monthly Capacity Payment, payable in arrears, to Seller. The Monthly Capacity Payment for each month of the Delivery Period is set forth in Section C of Appendix 3.1(a), and is subject to reduction in accordance with this Confirmation, including Sections 3.2 and 3.3 below. If the Monthly Capacity Payment is reduced in accordance with this Confirmation, SCE shall make the Reduced Monthly Capacity Payment in lieu of the Monthly Capacity Payment.

(b)

Variable O&M Payment: SCE shall pay Seller a monthly Variable O&M Payment, calculated as follows: n

Variable O&M Paymentm = Variable O&M Chargey *

 Qualifying Delivered Energy

i

i

where: Variable O&M Chargey is set forth in Appendix 3.1(b) m = the relevant month within the Delivery Period being calculated y = the Contract Year corresponding to month “m” n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” (c)

Start-Up Charge: SCE shall pay for the Start-Up Fuel, the Start-Up Charge and the Start-Up Aux Charge for each Start-Up unless specified otherwise in this Confirmation. In addition to all Energy produced after a Start-Up, all Energy produced prior to the Generating Unit achieving a Start-Up during the respective start-up cycle shall be for SCE’s account.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

(d)

(i)

If SCE aborts a start-up before the Generating Unit achieves full Start-Up, then SCE shall [a] pay for any natural gas consumed by the Generating Unit in connection with such aborted start-up, up to the applicable quantity of the Start-Up Fuel, [b] pay the Start-Up Charge and [c] pay the portion of the Start-Up Aux Charge that is proportional to [i] the amount of Start-Up Aux Energy (MWh) required from the beginning of the Start-Up to the time when such Start-Up was aborted as compared to [ii] the applicable Start-Up Time, provided that such payment shall not exceed the applicable Start-Up Aux Charge.

(ii)

If any Generating Unit is unable to generate or deliver Energy to the Energy Delivery Point after a Start-Up, but before the next scheduled shutdown of such Generating Unit for any reason other than a Force Majeure, SCE is not responsible for any charges under this Section 3.1(c) associated with the next Start-Up.

Fuel Payment: SCE shall pay to Seller a “Fuel Payment” equal to the sum of all Gas Commodity Costs, as defined in 3.1(d)(vi) below, for all applicable calendar days during a calendar month during the Delivery Period for the applicable calendar month. For purposes of calculating the Fuel Payment, the following definitions shall be used: (i)

Gas Index: The index price expressed in $/MMBtu for the applicable flow date published by Platts Gas Daily (in the internet publication currently accessed through www.platts.com) in the table entitled “Daily price survey” under the heading “Citygates” for “Kern River, delivered” under the column “Midpoint” plus $0.01/MMBtu. For the purposes of calculating the Fuel Payment, the Gas Index will be applied to Settlement Intervals on a calendar day basis with each day starting at hour ending 01:00 and not on a Gas Day basis. If the Gas Index ceases to be published, the Parties agree to deem the loss of the Gas Index a “Market Disruption Event” as defined in the Transition Master Agreement and follow the provisions outlined in Section 3.4 of the Transition Master Agreement.

(ii)

Gas Trading Day: The calendar day on which natural gas is traded corresponding to the applicable Gas Index. For example, in the absence of Holidays, a Gas Trading Day on a Monday reflects the day-ahead price applicable to gas flow on Tuesday. A Gas Trading Day on a Friday, in the absence of a Holiday, reflects the price for gas flow on Saturday, Sunday, and Monday.

(iii)

Required Natural Gas Quantity: The Required Natural Gas Quantity for each calendar day shall be expressed in MMBtu and equal to the sum of: [a]

[b]

(iv)

the quantity of natural gas required for each Settlement Interval of the calendar day, calculated by multiplying: (1)

MWh of Qualifying Delivered Energy in such Settlement Interval by

(2)

the lesser of [i] the Heat Rate specified in Appendix 5.3 applicable to the product of the Scheduled Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour, or [ii] the Heat Rate specified in Appendix 5.3 applicable to the product of the Qualifying Delivered Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour; and

any Start-Up Fuel required during the relevant calendar day; provided that in the event the duration of a Start-Up extends past one calendar day, then all of the Start-Up Fuel will be allocated to the calendar day associated with the first nonzero hourly schedule.

Day Ahead Gas Quantity: The quantity of natural gas (expressed in MMBtu), if any, determined by SCE on each Gas Trading Day for an estimated dispatch on all calendar days associated with such Gas Trading Day. For example, in the absence of a Holiday,

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

the Day-Ahead Gas Quantities for Saturday, Sunday, and Monday shall be calculated by SCE and provided to Seller on the immediately preceding Friday, and the Day-Ahead Gas Quantity for Tuesday shall be calculated by SCE and provided to Seller on the immediately preceding Monday.

3.2

(v)

Adjustment Gas Quantity: The Adjustment Gas Quantity for each calendar day shall equal the Required Natural Gas Quantity minus the Day-Ahead Gas Quantity corresponding to the applicable calendar day.

(vi)

Gas Commodity Cost: The Gas Commodity Cost shall equal the sum of the Day Ahead Gas Cost and Adjustment Gas Cost

(vii)

Day-Ahead Gas Cost: The Day-Ahead Gas Cost shall equal the Day-Ahead Gas Quantity multiplied by the applicable Gas Index for such Day-Ahead Gas Quantity.

(viii)

Adjustment Gas Cost: If the Adjustment Gas Quantity for a calendar day is: (a)

positive, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index published for and on the Gas Trading Day associated with the applicable Operating Day plus $0.35/MMBtu; or

(b)

negative, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the lower of the Gas Index (i) used for the Day-Ahead Gas Cost, or (ii) published for the next Gas Trading Day immediately following the applicable Operating Day; unless the Generating Unit(s) had a Forced Outage, that renders the entire unit(s) unavailable, declared for any Settlement Interval. In such cases, the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index used for the Day-Ahead Gas Cost, from the first date of the occurrence of the Forced Outage up to and including the date when the next Generating Unit Start-Up is completed.

Availability (a)

Capacity Payment Reduction. If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), (i) the Available Capacity of a Generating Unit is less than its Contract Capacity in any Settlement Interval in a month during the Delivery Period, or (ii) the Qualifying Delivered Energy from such Generating Unit is less than the Performance Tolerance Band Lower Limit in any Settlement Interval in a month during the Delivery Period, then the Capacity Payment Reduction for the affected Generating Unit for that month will be calculated as follows: (i)

For each Settlement Interval in the month, the “Price-Weighted Capacity Availability” is calculated as follows: Price-Weighted Capacity Availabilityi = (AMCPh(i) * Capacity Availabilityi) / AMCPavg(m) where: i = the Settlement Interval in month “m”

 MCP , if MCP  0 if MCP  0  0,

AMCP = 

h(i) = the Trading Hour corresponding to Settlement Interval “i” being calculated avg(m) = the simple average over all Settlement Intervals in month “m”

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

For purposes of such calculation, Capacity Availability for any Settlement Interval shall not exceed the applicable Contract Capacity. (ii)

Using the Price-Weighted Capacity Availability calculated above, the “Price-Weighted Monthly Capacity Availability” for month “m” is calculated as follows: n

Price-Weighted Monthly Capacity Availabilitym =

 Price-Weighted Capacity Availabilityi i

where: m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” (iii)

Using the Price-Weighted Monthly Capacity Availability calculated above, the “Capacity Price Adjustment Factor” for month “m” is calculated as follows: Capacity Price Adjustment Factorm = Price-Weighted Monthly Capacity Availabilitym / (Q * n) where: m = the relevant month within the Delivery Period being calculated Q = the Contract Capacity n = the number of Settlement Intervals in month “m”

(iv)

Finally, using the Capacity Price Adjustment Factor calculated above, the “Capacity Payment Reduction” for month “m” is calculated as follows: Capacity Payment Reductionm,CCGT / BOILER = 0.85 * Monthly Capacity Payment * (1 –Capacity Price Adjustment Factor)

(b)

Ancillary Services Capacity Payment Reduction: If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), for each Ancillary Service listed in Section F of Appendix 1.4, the A/S Availability of a Generating Unit is less than the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4 in any Settlement Interval of a month, then the A/S Capacity Payment Reduction for the Generating Unit for that month will be calculated as follows: (i)

The “Monthly Available A/S Capacity” for month “m” is calculated as follows: n

Monthly Available A/S Capacitym =

 A/S Availability k

i,k

i

where: m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” k = the applicable Ancillary Service

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

For purposes of such calculation, for each Ancillary Service, A/S Availability for any Settlement Interval shall not exceed the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4. (ii)

Using the Monthly Available A/S Capacity calculated above, the “A/S Price Adjustment Factor” for month “m” is calculated as follows: A/S Price Adjustment Factorm = Monthly Available A/S Capacitym / A/S Maximum Capacityk * n) (

 k

where: A/S Maximum Capacity is set forth in Section F of Appendix 1.4 m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” k = the applicable Ancillary Service (iii)

Using the A/S Price Adjustment Factor calculated above, the “A/S Capacity Payment Reduction” for month “m” is calculated as follows: A/S Capacity Payment Reductionm,CCGT/ BOILER = 0.15 * Monthly Capacity Payment * (1 – A/S Price Adjustment Factor)

(c)

3.3

Reduced Monthly Capacity Payment: The “Reduced Monthly Capacity Payment” shall be equal to (i) the Monthly Capacity Payment less (ii) the sum of [a] the Capacity Payment Reduction and [b] the A/S Capacity Payment Reduction.

Other Events Affecting Availability (a)

If Seller fails to take any action necessary to make the Product (or any portion of the Product) deliverable or otherwise available to SCE at the Energy Delivery Point, including maintenance, repair, or replacement of equipment in Seller’s possession or control that must be used for SCE to take delivery of the Product after, or transmit the Product from, the Energy Delivery Point, or such equipment fails for any reason including by reason of Force Majeure or any Outage, then, to the extent SCE is unable to take delivery of the Product after, or to transmit the Product from, the Energy Delivery Point by reason of such failures by Seller, the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(b)

If Seller fails to take any action within its control that is necessary to deliver the Natural Gas Requirements to the Generating Unit(s), including maintenance, repair or replacement of equipment in Seller’s possession or control that must be used to deliver the Natural Gas Requirements to the Generating Unit(s), or such equipment in Seller’s possession or control fails for any reason, including by reason of Force Majeure or any Outage, then, to the extent the Natural Gas Requirements are unable to be delivered to the Generating Unit(s), the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(c)

If the IFA, the PGA, or the MSA are not in effect at any time during the Delivery Period, the Generating Units shall be deemed to be unavailable for the Settlement Intervals during which such

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

agreement or agreements are ineffective, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above. (d)

If Seller starts-up or operates any Generating Unit other than (i) pursuant to a Dispatch Notice or (ii) pursuant to a Non-SCE Dispatch, the Generating Unit shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

ARTICLE 4 FUEL RESPONSIBILITIES 4.1

SCE’s Obligation

SCE shall provide the Day Ahead Gas Quantity to Seller by 6:00 AM (PPT) on the Gas Trading Day applicable to each calendar day of the Delivery Period and be responsible for costs associated with providing the Required Natural Gas Quantity to the Generating Units solely through the Fuel Payment as set forth in Section 3.1(d). SCE shall not be obligated to reimburse Seller for any separate charges assessed to Seller for gas transportation surcharges, fuel retention charges, imbalances, penalties, storage costs, or fuel-related taxes. 4.2

Seller’s Obligation

Seller shall be responsible for managing, nominating, scheduling, balancing, and transporting all of the Natural Gas Requirements needed to operate each Generating Unit. Seller shall also be responsible for all costs of natural gas associated with a Seller’s Initiated Test as set forth in Article 10.

ARTICLE 5 COMBINED HEAT AND POWER (“CHP”) PROGRAM PROVISIONS 5.1

CHP Program Procurement and Seller Eligibility

Seller and SCE acknowledge and agree that SCE is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by SCE pursuant to this Confirmation is and shall be deemed to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to SCE that as of the Confirmation Effective Date, Generating Unit # 1 and Generating Unit # 3, together with the generating units that are subject to the obligations in the Transition PPA, constitute a Qualifying Facility. 5.2

CPUC Approval; FERC Approval (a)

Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report.

5.3

(c)

Failure to obtain CPUC Approval in accordance with this Section 5.2(a) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of SCE to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval.

(d)

Failure to obtain FERC Approval in accordance with this Section 5.2(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

Provision of Information

Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement. 5.4

Termination Right of Seller; Settlement Amount (a)

Seller has the right to terminate this Confirmation if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected by Buyer in a competitive solicitation. In such an instance, the termination of this Confirmation will be effective as of midnight the day before the commencement of any delivery period for any electric energy, capacity or attributes from the Generating Facility which is selected by Buyer in such competitive solicitation.

(b)

Seller has the right to terminate this Confirmation upon providing to Buyer at least 180 days advance notice if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected in a competitive solicitation by a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 5.4(b) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

(c)

Seller has the right to terminate this Confirmation upon providing to Buyer at least 180 days advance notice if Seller (or any venture in which Seller is a participant) and the Generating Facility jointly enter into an agreement for the sale of electric energy, capacity or attributes with a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

(other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 5.4(c) at a later date so long as Seller provides Buyer at least 90 days advance Notice. (d)

Notwithstanding anything to the contrary, no Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation under Section 5.4.

ARTICLE 6 SCHEDULING COORDINATOR SERVICES 6.1

SCE as Scheduling Coordinator

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall take all actions and execute and deliver to SCE and the CAISO all documents necessary to authorize or designate SCE as Scheduling Coordinator (“SC”) for each of Generating Unit # 1 and Generating Unit # 3 with the CAISO effective as of the beginning of the Delivery Period. Seller shall not be entitled to any payment under this Confirmation until SCE is fully authorized as the SC for each such Generating Unit. During the Delivery Period, and after SCE is designated as SC for a Generating Unit, Seller shall not authorize or designate any other party to act as SC, nor shall Seller perform for its own benefit the duties of SC, and Seller shall not revoke SCE’s authorization to act as SC unless agreed to in writing by SCE. SCE shall submit bids and schedules to the CAISO in accordance with the Tariff and, subject to Article 9 below, the Operating Restrictions. Seller shall reasonably cooperate with SCE in performing any actions necessary prior to the start of the Delivery Period to allow each of Generating Unit # 1 and Generating Unit # 3 to be (i) dispatched (or otherwise scheduled to operate) for the first day of the Delivery Period and (ii) reported to or scheduled with the CAISO pursuant to the Tariff, either through SLIC or as otherwise required by the CAISO, as being in an outage at the commencement of the Delivery Period. All CAISO costs and revenues (including credits and other payments) associated with a dispatch of Generating Unit # 1 or Generating Unit # 3 on the first day of the Delivery Period that are received by Seller or their SC on the day prior to the Delivery Period shall be for SCE’s account. 6.2

Notices

Subject to Seller complying with its obligations under this Confirmation, SCE, as SC, shall submit all notices and updates required under the Tariff regarding each Generating Unit’s status to the CAISO. Seller will comply with Article 9 of this Confirmation in providing such notices and updates. 6.3

CAISO Settlements

As SC, SCE shall be responsible for all settlement functions with the CAISO related to the Generating Units. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to the Generating Units, including any invoices or settlement data, in the format reasonably requested by SCE. 6.4

Terminating SCE’s Designation as SC

At least thirty (30) days prior to the expiration of the Delivery Period, the Parties will take all actions necessary to terminate the designation of SCE as SC as of 11:59 p.m. on the final date of the Delivery Period (“SC Replacement Date”). Such actions include the following: (a) Seller shall (i) submit to the CAISO a designation of a new SC to replace SCE effective as of the SC Replacement Date and (ii) cause its newly designated SC to submit a letter to the CAISO accepting the designation; and (b) SCE shall submit a letter to the CAISO resigning as SC effective as of the SC Replacement Date. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement SC. 6.5

Duties Related to Resource Adequacy Resources

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If a Generating Unit is designated as a Resource Adequacy Resource, the following will apply: (a)

Seller shall take all actions necessary in order to allow SCE to reasonably perform its duties as an SC for a Resource Adequacy Resource, including, but not limited to, providing all information needed for SCE to include the Generating Units on SCE’s Supply Plan; and

(b)

SCE shall use the Resource Adequacy Availability Management (“RAAM”) software to allow Seller to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”), provided, (i) SCE is not required to use or change its utilization of SCE owned or controlled assets or market positions, to allow Seller to utilize the Substitution Rules, (ii) Seller, at its own expense, provides substitute capacity that complies with the Substitution Rules, (iii) Seller provides, as soon as practicable, but no later than 5:00 a.m. PPT the day bids are due in the IFM for the day Seller seeks to substitute capacity for, all information to SCE needed to substitute capacity pursuant to the Substitution Rules, including, but not limited to, the substitution start and end dates, the Resource ID for the substitute unit, a short description of the outage, the outage ID from SLIC application, and the amount of capacity to be substituted, (iv) SCE’s duties to take action under this subsection (b) are solely limited to inserting one (1) substitution request through RAAM per day; and (v) Seller causes, and is responsible for, the SC of the generating unit Seller seeks to substitute with to cooperate with SCE in making a substitute request and SCE is not responsible or liable for any costs, damages, penalties, charges, or liabilities (“Substitution Costs”) associated with such SC’s failure to cooperate or take the proper action; provided, further, if the CAISO develops a tool, application, or other means, for Seller to submit its own substitution request, then SCE shall not be required to take any action under this Section 6.5(b) to allow Seller to utilize the Substitution Rules. In no event shall SCE be responsible or liable for any Substitution Costs associated with Seller’s inability to utilize the Substitution Rules or rejection by the CAISO of any substitute capacity for any reason, including, but not limited to, any RAAM software limitations or failures, unless SCE is required to take action and such Substitution Costs or rejection result solely from SCE’s actions.

Seller shall provide the information set forth in Section 6.5(b)(iii) through the Outage Management System. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide such information through (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission of such information as soon as practicable.

ARTICLE 7 RMR DESIGNATION 7.1

RMR Contract

Upon the request or designation by the CAISO that any of the Generating Units be an RMR Unit, whether such request or designation is made directly by the CAISO or at the CAISO’s direction through the Scheduling Coordinator, Seller shall enter into an RMR Contract with CAISO under terms and conditions reasonably acceptable to SCE and Seller. Seller shall not otherwise pursue or enter into an RMR Contract without SCE’s consent. If any Generating Unit is or becomes an RMR Unit during the Delivery Period, then for any dispatch by CAISO under the RMR Contract, the Operating Restrictions under this Confirmation will be subject to and superseded by any operating restrictions set forth in the RMR Contract or in the CAISO Master File for those Generating Units. Nothing in this Confirmation shall be construed to be a limitation on SCE’s right as a Transmission Owner under the Tariff to file with, or petition, to the FERC any objection or comments relating to any such RMR Contract or any actions SCE or CAISO intend to take with respect to any such RMR Contract. Seller represents, warrants, and covenants to SCE that if an RMR Contract for any Generating Unit for a period in which it is subject to the obligations in this Confirmation goes into effect at any time during the Term, no

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assignment of such RMR Contract to SCE will be required in connection with this Transaction. The Parties agree that neither this Confirmation nor this Transaction shall operate as an assignment of any such RMR Contract from Seller to SCE, and that in no event shall SCE be required to assume the obligations of Seller under any such RMR Contract. 7.2

RMR Settlements

If a Generating Unit is designated as a CAISO RMR Unit, then no later than thirty (30) days after such designation by CAISO, Seller shall (i) authorize SCE to act as Seller’s representative (“RMR Settlement Coordinator”) to perform all RMR settlement functions for the RMR Units, (ii) authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder, and (iii) irrevocably assign to SCE all rights to receive any and all payments under the RMR Contract for the Delivery Period. Seller shall take all actions and execute and deliver to SCE all documents or contracts necessary, including any confidentiality agreements or other documents required under the RMR Contract, to authorize or designate SCE with the CAISO as its RMR Settlement Coordinator, and authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder. During the Delivery Period, Seller shall not authorize or designate any other party to act as RMR Settlement Coordinator, nor shall Seller perform for its own benefit the duties of RMR Settlement Coordinator, and Seller shall not revoke SCE’s authorization to act as RMR Settlement Coordinator unless agreed to by SCE. Upon SCE’s designation as the RMR Settlement Coordinator, SCE will be responsible for all RMR settlement functions in accordance with the Tariff and the RMR Contract, including rendering monthly RMR invoices to CAISO, settling any RMR charges incurred or RMR revenues earned, and resolving any RMR-related issues directly with CAISO. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to each of Generating Unit # 1 and Generating Unit # 3 (whether or not such Generating Units are subject to the obligations of this Confirmation at the time such correspondence or communication with the CAISO is received by Seller), including any invoices or settlement data, in the format reasonably requested by SCE. Upon receipt of any invoice from the CAISO for an RMR Unit (“RMR Invoice”), Seller shall promptly deliver such RMR Invoice to SCE. If the RMR Invoice amount is a charge from CAISO to Seller, Seller shall submit an invoice to SCE setting forth the amounts owed under the RMR Invoice, and SCE shall pay such amount to Seller for remission to CAISO within ten (10) Business Days after SCE’s receipt of such invoice. If the RMR Invoice amount is a payment from CAISO to Seller, Seller shall remit the amount of such payment to SCE within ten (10) Business Days after Seller’s receipt of such payment. To secure Seller’s obligations to remit to SCE any payments received under an RMR Contract or pursuant to an RMR Invoice, Seller hereby grants to SCE a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all revenues and accounts receivable of Seller with respect to the RMR Contract, and any and all proceeds resulting therefrom (collectively, “RMR Revenues”), whether now or hereafter held by, on behalf of, or for the benefit of, SCE, and Seller agrees to take such action as SCE reasonably requires in order to perfect SCE’s first-priority security interest in, and lien on (and right of setoff against) such RMR Revenues. SCE shall be the Secured Party with respect to the RMR Revenues and shall have all the rights and remedies of the Secured Party under the Transition EEI Agreement with respect to those RMR Revenues. 7.3

Disputes of RMR Invoices

The Parties agree that all RMR Invoices are subject to the Tariff and may be adjusted by the CAISO, or disputed by SCE, as RMR Settlement Coordinator, in accordance with the Tariff. The Parties agree that all RMR Invoices are subject to dispute between the Parties in accordance with Article Six of the Transition Master Agreement; provided, that the time limitation for adjustments or disputes of invoices set forth in Section 6.3 of the Transition Master Agreement shall not apply to RMR Invoices. Notwithstanding anything to the contrary contained in Articles Six or Ten of the Transition Master Agreement, the Parties agree that the obligations under this Article 7 with respect to the payment of RMR Invoices, or the adjustment of such RMR Invoices, shall survive the expiration or termination of this Confirmation for a period of one year beyond the time period which CAISO may adjust, modify

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or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the Tariff. 7.4

Terminating SCE’s Designation as RMR Settlement Coordinator

SCE’s designation as RMR Settlement Coordinator will remain in effect until the last applicable RMR Invoice and the data associated therewith is received by SCE and SCE completes all RMR settlement functions associated with such final RMR Invoice. In no event shall SCE be the RMR Settlement Coordinator for any operating day that is not within the Delivery Period. A new SC or RMR Settlement Coordinator shall not affect SCE’s ability to receive RMR settlement payment for any Generating Unit for any operating day during the Delivery Period when an RMR contract is in effect between Seller and the CAISO for such Generating Unit.

ARTICLE 8 CAISO AND DELIVERY DEVIATION CHARGES 8.1

CAISO Costs and Revenues

Except as otherwise set forth in this Confirmation, SCE shall be responsible for CAISO costs and receive all CAISO revenues (including credits and other payments) incurred in connection with providing SC services, including costs and revenues associated with SCE and CAISO dispatches of any Generating Unit. The procedures and calculation methodologies set forth in this Article 8 regarding CAISO costs and revenues are in respect to each Generating Unit. 8.2

CAISO Sanctions

If, during the Term, the CAISO implements or has implemented any sanction or penalty related to scheduling, outage reporting, or generator operation, and any such sanctions or penalties are imposed upon the Generating Unit(s) or to SCE as SC due solely to the actions or inactions of Seller, the cost of the sanctions or penalties shall be the Seller’s responsibility. 8.3

Scheduling and Delivery Deviation Charge

Seller shall pay SCE an SDD Charge if during any Settlement Interval the Qualifying Delivered Energy is less than the Performance Tolerance Band Lower Limit for such Settlement Interval. The SDD Charge is calculated as follows: If A < B, then SDD Charge = 0.5 * (B – A) * C where: A = Qualifying Delivered Energy for the Settlement Interval; B = Performance Tolerance Band Lower Limit; and C = SDD Price. Upon CAISO’s implementation of UDP, or any subsequent changes regarding the calculation of UDP, the Parties agree to negotiate in good faith to amend the SDD Charge calculation as necessary to maintain the economic balance of benefits and burdens contemplated under this Section 8.3. 8.4

SDD Administrative Charge

Seller shall pay SCE an SDD Administrative Charge if during any Settlement Interval Delivered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, for

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such Settlement Interval. The SDD Administrative Charge is calculated as follows: SDD Administrative Charge = Absolute Value (E – D) * F where: D = Delivered Energy for the Settlement Interval; E = Scheduled Energy for the Settlement Interval; and F = SDD Admin Price. 8.5

Allocation of Standard Capacity Product Payments and Charges

Seller agrees that, if the Generating Unit is a Resource Adequacy Resource, then it is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account. 8.6

Allocation of Charges Related to Generator Replace Tariff Provisions

If (a) a Generating Unit is designated as a Resource Adequacy Resource and (b) FERC approves or modifies the Tariff whereby, during periods that the Generating Unit is on a Planned Outage, the SC for a Resource Adequacy Resource is required to (i) replace the Generating Unit with a resource that is not a Resource Adequacy Resource or (ii) face the imposition of a charge, cost, sanction and/or penalty for failing to replace that Generating Unit, then Seller is responsible for (x) replacing the Generating Unit with a resource that is not a Resource Adequacy Resource, and (y) any and all charges, costs, sanctions and/or penalties for failing to replace all or a portion of the Generating Unit. Seller agrees that SCE is not required to take any action, or use or change its utilization of its owned or controlled assets or market positions, to allow Seller to replace the Generating Unit with a resource that is not a Resource Adequacy Resource; provided that SCE in its capacity as SC shall remain liable for compliance by it with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 9 AVAILABILITY NOTICES, BIDS, AWARDS AND DISPATCH 9.1

Notice of Availability

With respect to each Operating Day, no later than two (2) Business Days before each Trading Day, Seller shall provide to SCE using an SCE-provided web-based system (“Outage Management System”) an hourly schedule of the Available Capacity (for both Energy and Ancillary Services) that each Generating Unit is expected to have available for each hour of the applicable Operating Day (the “Availability Notice”). Seller must update SCE immediately using the Outage Management System if the Available Capacity of any Generating Unit changes or is likely to change after the Availability Notice has been submitted to SCE. Seller must follow up each such update through the Outage Management System with a telephonic update to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e). Seller shall accommodate SCE’s reasonable requests for changes in the time or form of delivery of the Availability Notices. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide Availability Notices using the form attached in Appendix 9.1 by (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission notice of such availability as soon as practicable.

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9.2

9.3

Dispatch Notices and Operating Restrictions (a)

Dispatch Notices. SCE will have the right to dispatch each Generating Unit, seven (7) days per week and twenty-four (24) hours per day (including Holidays) and (i) at any level between PMin and Contract Capacity, inclusive, and (ii) at any level between Contract Capacity and PMax if instructed by the CAISO by providing Dispatch Notices to Seller electronically, subject to the terms and conditions set forth in this Confirmation. Subject to the Operating Restrictions, each Dispatch Notice will be effective unless and until SCE modifies such Dispatch Notice by providing Seller with an updated Dispatch Notice. If an electronic submittal is not possible for reasons beyond SCE’s control, SCE may provide Dispatch Notices by (in order of preference) electronic mail, facsimile transmission, or telephonically to the Seller personnel designated to receive such communications as listed in the Appendix 9.2(e). Day-Ahead Dispatch Notices, in the absence of an electronic submittal, shall be provided in a form substantially similar to Appendix 9.2(a). In addition to any other requirements set forth in this Confirmation, all Dispatch Notices will be made in accordance with the Tariff.

(b)

Start-Up Notices. If a Dispatch Notice includes a Start-Up, Seller shall notify SCE electronically when the respective Generating Unit has initiated a turbine start and again when that Generating Unit is synchronized and at Minimum Load ready to be dispatched to the applicable dispatch instruction. Seller shall provide an electronic or facsimile copy of a completed Start-Up Notice, in the form attached to this Confirmation in Appendix 9.2(b), to SCE within twenty-four (24) hours of the Start-Up. When a Dispatch Notice requires a Start-Up or shutdown, Seller will be responsible for coordinating all required switchyard switching with the respective grid control center, if applicable.

(c)

Operating Restrictions. The Operating Restrictions associated with the Product are specified in Appendix 1.4. In providing a Dispatch Notice, SCE shall use reasonable efforts to comply with the applicable Operating Restrictions. If SCE submits a Dispatch Notice that does not conform with the Operating Restrictions, then Seller shall immediately notify SCE of the non-conformity and SCE will modify its Dispatch Notice to conform to the applicable Operating Restrictions. Until such time as SCE submits a modified Dispatch Notice, Seller shall operate the applicable Generating Unit and deliver the Product in accordance with the Operating Restrictions.

(d)

Daily Operating Report. Seller shall provide SCE the Daily Operating Report, in the form attached in Appendix 9.2(d), the day immediately after each Operating Day, for all Generating Units.

(e)

Communication Protocols. The Parties shall agree to the communication protocols outlined in Appendix 9.2(e) to facilitate exchange of information between the Parties.

CAISO Dispatch

Any award or dispatch of a Generating Unit by the CAISO for any reason (whether pursuant to an RMR Contract, must offer obligations, Energy dispatches or otherwise), shall be deemed to be a dispatch by SCE for purposes of this Confirmation. The Energy dispatched shall be for SCE’s benefit hereunder, and SCE shall pay the costs of such CAISO awards and dispatches in accordance with the terms of this Confirmation as if such dispatches were directed by SCE. SCE shall be entitled to receive and retain for its own account any and all CAISO revenues for such awards and dispatches, including any availability payments under an RMR Contract for any Generating Unit. In no event shall a dispatch by the CAISO be considered a Non-SCE Dispatch pursuant to this Confirmation. CAISO dispatches following any Seller Initiated Test pursuant to Section 10.1 shall not obligate SCE for any associated costs incurred in starting any Generating Unit for, or operation during, such testing period. 9.4

Non-SCE Dispatch

During the Delivery Period, Seller shall not start-up or operate any Generating Unit other than (a) pursuant to a Dispatch Notice or (b) pursuant to a Non-SCE Dispatch. Seller shall, to the extent possible, notify SCE no later than 5:00 a.m. PPT at least two (2) Business Days in advance of the Trading Day of any start-up or operation

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pursuant to a Non-SCE Dispatch, and shall, except as otherwise required by Applicable Law, delay such start-up or operation if requested by SCE. Seller shall indemnify, defend, and hold SCE harmless against the costs or losses of SCE resulting from a Non-SCE Dispatch, including all (i) charges, sanctions, and penalties imposed by CAISO, and (ii) Seller’s Gas Costs incurred pursuant to any such start-up or operation. Imbalance Energy revenues net of any charges, sanctions, and penalties imposed by CAISO for a Non-SCE Dispatch shall be for Seller’s account.

ARTICLE 10 TESTING 10.1

Testing

Seller may, at times and for durations reasonably agreed to by SCE, conduct necessary testing of the Generating Units. (a) Seller is permitted to conduct such testing during the hours in which Seller receives a Dispatch Notice (“SCE Dispatched Test”). Seller shall not be obligated to pay for the Fuel Payment relating to such SCE Dispatched Test, and SCE shall be responsible for all CAISO costs incurred and receive all revenues during such SCE Dispatched Test in accordance to Section 8.1 of this Confirmation. (b) Subject to Section 10.1(a), if Seller wishes to schedule and conduct a test (“Seller Initiated Test”), SCE shall not be obligated to pay the Fuel Payment to Seller, and Seller shall pay for all costs (including, but not limited to, start-up, fuel and/or transportation costs) relating to and arising out of such Seller Initiated Test in accordance with Section 9.4 of this Confirmation, and SCE shall pay to Seller, in the month following SCE’s receipt of such CAISO revenues, such revenues net of any resource specific charges, penalties, or sanctions associated with the Energy generated and delivered during such Seller Initiated Test. To the extent such Seller Initiated Test prevents SCE from dispatching any Generating Unit as it would have absent such test, then, in accordance with the Section 3.2 of this Confirmation, the Generating Unit will be deemed unavailable. Seller must notify SCE of any Seller Initiated Test no later than 5:00 a.m. PPT at least three (3) Business Days in advance of the Trading Day of any start-up, operation or operational limitation(s) pursuant to the requested test. If Seller Initiated Test is agreed upon by SCE, SCE shall have the option to submit a SelfSchedule in the IFM for the agreed upon testing day for a duration the greater of (i) the number of hours required to complete the test, or (ii) the Minimum Run Time as referenced in Section B of Appendix 1.4. Notwithstanding anything to the contrary in this Confirmation, such Self-Schedule is not considered a Dispatch Notice. 10.2

SCE Annual Test

At least once per calendar year at SCE’s request, SCE has the right to require Seller to demonstrate, pursuant to the protocols set forth in Appendix 10.2 (the “SCE Annual Test”), each Generating Unit’s ability to provide the Product in accordance with the terms of this Confirmation. In addition, as part of the SCE Annual Test, SCE may inspect the Generating Facility to confirm the configurations of the Generating Unit(s) provided for in Appendix 1.4. The SCE Annual Test shall be at a time mutually agreed to by the Parties. If, during an SCE Annual Test, a Generating Unit fails to demonstrate its ability to provide the Product or any portion thereof (a “Failed Test”), Seller shall, at Seller’s cost and expense, promptly make all necessary repairs to such Generating Unit, and any portion thereof, and/or take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation. The results of any Failed Test will be used to determine the Available Capacity for the applicable Generating Unit, and accordingly, Reduced Monthly Capacity Payments shall apply for such Generating Unit until Seller demonstrates, in accordance with Appendix 10.2, a successful test. Seller agrees that any subsequent test that is required to demonstrate compliance for a Failed Test shall be a Seller Initiated Test.

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ARTICLE 11 OUTAGES 11.1

Planned Outages

No later than 60 days prior to the Delivery Period, and no later than January 1, April 1, July 1, and October 1 of each calendar year thereafter throughout the Term, Seller shall submit to SCE the portion of the Seller’s schedule of proposed Planned Outages (“Outage Schedule”) for the following twenty-four (24) month period that overlaps the Delivery Period via the Outage Management System. If the Outage Management System is not available, Seller shall submit the Outage Schedule in substantially the form set forth in Appendix 11.1. Within twenty (20) Business Days after its receipt of an Outage Schedule, SCE shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Accepted Electrical Practices, accommodate SCE’s requests regarding the timing of any Planned Outage. Seller shall cooperate with SCE to arrange and coordinate all Outage Schedules with the CAISO in compliance with all CAISO Outage scheduling and reporting requirements. Seller will communicate to SCE all changes to a Planned Outage including estimated time of return of each Generating Unit as soon as practicable after the condition causing the change becomes known to Seller. 11.2

11.3

Restrictions to Planned Outages (a)

No Planned Outages shall be scheduled or planned from each May 1 through September 30 during the Delivery Period for any Generating Unit subject to this Confirmation, without prior written consent from SCE.

(b)

In the event that the Seller has a Planned Outage for any Generating Unit subject to this Confirmation that becomes coincident with a CAISO-declared system emergency, Seller shall make all reasonable efforts to reschedule such Planned Outage.

Notice of Forced Outages

Seller shall communicate Forced Outages by telephoning SCE’s Generation Operations Center within ten (10) minutes of the commencement of the Forced Outage, at the telephone numbers listed in Appendix 9.2(e). Seller shall utilize SCE’s Outage Management System to enter Outage information as required by the Tariff within twenty (20) minutes of the Forced Outage. If the CAISO imposes a sanction or penalty upon SCE as SC due to Seller’s failure to timely provide SCE with a report of a Forced Outage or Planned Outage for any Generating Unit subject to this Confirmation, Seller shall be responsible for such sanction or penalty. 11.4

Reports of Forced Outages or Planned Outages

Seller shall promptly prepare and provide to SCE, using the Outage Management System or forms, all reports of Forced Outages or Planned Outages for any Generating Unit subject to this Confirmation that SCE may reasonably require for the purpose of enabling SCE to comply with CAISO requirements or any Applicable Laws. Seller shall provide to SCE notice of a Planned Outage no later than seventy-two (72) hours prior to the beginning of any Planned Outage. Seller shall also report all Forced Outages and Planned Outages in the Daily Operating Report. 11.5

Inspection

In the event of a Forced Outage, SCE shall have the right to inspect any Generating Unit and all records relating thereto on any Business Day and at a reasonable time, and Seller shall reasonably cooperate with SCE during any such inspection.

ARTICLE 12

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METERING, COMMUNICATIONS, AND TELEMETRY 12.1

SCE Access

All communication, metering, telemetry, and associated generation operation equipment will be centralized into each Generating Unit’s Distributed Control System (“DCS”). Seller shall configure each Generating Unit’s DCS so that SCE may access it via the Generation Management System (“GMS”) from SCE’s Generation Operations Center (“GOC”). Seller shall ensure that the access link will provide a monitoring and control interface to enable automatic dispatch of each Generating Unit. Seller shall link the systems via an approved SCE communication network, utilizing existing industry standard network protocol, as approved by SCE. The connection will be bidirectional in nature and used by the Parties to exchange all data points to and from the GOC. SCE and Seller shall each have shared access to information concerning gas data (including data regarding nominations, confirmations, allocations, imbalances, and usage) through electronic bulletin boards or remote meter reading devices with respect to all Natural Gas Requirements for each Generating Unit. Seller shall be responsible for the costs of installing, configuring, maintaining and operating the DCS for each Generating Unit. 12.2

Control Logic

Seller will ensure that each Generating Unit’s DCS control logic will be configured to control the Generating Unit in multiple plant configurations as applicable. Each Generating Unit’s control logic will incorporate control signals from multiple locations to perform Energy dispatch, Ancillary Services, and supplemental energy functions. Control logic will perform all coordinated megawatt control and Automatic Generation Control (“AGC”) independently for each Generating Unit. 12.3

Delivery of Data

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall provide SCE with all facility and metering information necessary to communicate with SCE, including the information set forth in Appendix 12.3. 12.4

Satellite Communication System

Seller is responsible for installing, testing, commissioning, and maintaining the Satellite Communications System (“SCS”) for each Generating Unit in accordance with instructions provided by SCE and the SCS vendor. Seller shall grant SCE reasonable access to the Generating Units during regular business hours for routine calibration and maintenance of the SCS at any time prior to the expiration of the Delivery Period. SCE may, at any time, halt the installation, testing, commissioning, or maintenance of the SCS. SCE shall be responsible for the costs associated with installation, testing, commissioning, and maintenance of the SCS, and will provide the SCS to Seller for installation.

ARTICLE 13 OPERATION, MAINTENANCE, AND REPAIR 13.1

Seller’s Operation Obligations During the Delivery Period: (a)

Seller shall operate each Generating Unit in accordance with Accepted Electrical Practices, Applicable Laws, Permit Requirements, applicable California utility industry standards, including the standards established by the California Electricity Generation Facilities Standards Committee pursuant to Public Utilities Code Section 761.3 and enforced by the CPUC, CPUC General Order 167, and CAISO mandated standards, as set forth in the Tariff (collectively, “Industry Standards”);

(b)

Seller shall maintain a daily operations log for each Generating Unit which shall include information on power production, fuel consumption and efficiency (if applicable), availability, maintenance performed, Outages, changes in operating status, inspections and any other significant events

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related to the operation of each Generating Unit. In addition, Seller shall maintain all records applicable to each Generating Unit, including the electrical characteristics of the generators and settings or adjustments of the generator control equipment and protective devices. Information maintained pursuant to this Section 13.1 shall be provided to SCE, within five (5) Business Days of SCE's request; and (c)

13.2

Seller shall maintain and make available to SCE and the CPUC, or any division thereof, records, including the plant operations logbooks demonstrating that the Generating Units are operated and maintained in accordance with Industry Standards. Seller shall comply with all reporting requirements and permit on-site audits, investigations, tests, and inspections permitted or required under Industry Standards.

Seller’s Maintenance and Repair Obligations During the Delivery Period: (a)

Seller shall inspect, maintain, and repair each Generating Unit, and any portion thereof, in accordance with applicable Industry Standards. Seller shall maintain and deliver to SCE within five (5) Business Days upon request, maintenance and repair records and plant equipment test data of each Generating Unit; provided, however, if Seller must obtain such records and data from a thirdparty, Seller shall promptly request such records and data from the applicable third-party and shall provide the requested records and data to SCE within five (5) Business Days of receipt.

(b)

In the event that: (i)

an SCE Annual Test demonstrates that the Available Capacity of a Generating Unit is less than or equal to seventy-five percent (75%) of Contract Capacity, or

(ii)

an equipment failure with respect to a Generating Unit results in the Available Capacity of such unit being less than or equal to seventy-five percent (75%) of Contract Capacity on average for a period of time exceeding seven (7) days,

Seller shall repair such Generating Unit in accordance with Accepted Electrical Practices and the procedure set forth in this Article 13. Within fourteen (14) days of any such failure, Seller shall complete a Successful Repair or present to SCE a written report providing a description of the reason for the failure and a plan and schedule for completing a Successful Repair within the time specified in the repair plan (“Repair Plan”). If SCE and Seller disagree about the Repair Plan, SCE may, at its expense, hire an independent third party engineering firm reasonably acceptable to Seller (“IE”), to assess the situation and make recommendations for completing a Successful Repair. Upon SCE providing two (2) Business Days notice, Seller shall grant the IE and SCE personnel access to the Generating Facility and all relevant operational log books, maintenance records and reports. Seller shall use best efforts to follow the recommendations of the IE’s engineering report for achieving a Successful Repair. Until a Successful Repair is demonstrated, the Generating Unit(s) will be deemed unavailable for purposes of Section 3.2 of this Confirmation; provided, upon Seller’s demonstration of a Successful Repair, the Generating Unit(s) will be deemed available retroactive to the hour that such Successful Repair was initiated; (c)

Subject to Section 13.2(b), Seller shall promptly make all necessary repairs to each Generating Unit, and any portion thereof, and take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation; and

(d)

Seller shall not allow the Available Capacity of any Generating Unit to fall below seventy-five percent (75%) of Contract Capacity on average for a period of:

19

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

13.3

(i)

six (6) months (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) due to Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such six (6) month period (or longer cure period identified in the IE’s written report); or

(ii)

sixty (60) days (whether or not consecutive) within a rolling twelve (12) month period (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) for any reason or circumstance, including Forced Outage, but excluding Planned Outage and Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such sixty (60) day period (or longer cure period identified in the IE’s written report).

Operational Representations, Warranties, and Covenants by Seller

Seller represents, warrants, and covenants with respect to Sections 13.3(a) through (d) and Seller covenants with respect to Section 13.3(e) to SCE that: (a)

Prior to the start of the Delivery Period, Seller has executed a PGA and MSA; Seller has delivered to SCE a true and complete copy of such PGA and MSA; and such PGA and MSA, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the duration of the Delivery Period; provided that Seller shall be allowed to agree to any amendment or modification to the PGA and/or MSA if FERC approves a new form of such agreements for the CAISO, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10) Business Days of such amendment or modification.

(b)

Prior to the start of the Delivery Period, Seller has executed all necessary grid connection, maintenance, or transmission facility services agreements; Seller has delivered to SCE a true and complete copy of such agreements; and such agreements, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the Term; provided that if FERC authorizes the Transmission Owner to amend or modify such agreements with Seller, Seller is authorized to accept any such FERC-approved modified or amendment agreement, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10) Business Days of such amendment or modification.

(c)

Prior to the start of the Delivery Period, Seller has good and defensible title, or valid and effective leasehold rights in the case of leased property, to each Generating Unit subject to this Confirmation , free and clear of all liens, charges, claims, pledges, security interests, equities, and encumbrances of any nature whatsoever other than (i) the lien of current taxes not delinquent; (ii) liens, charges, claims, pledges, security interests, equities, and encumbrances that in the aggregate are not substantial in amount and do not detract from or interfere with the ability of Seller to deliver the Product; or (iii) liens listed in Appendix 13.3(c) delivered by Seller to SCE prior to the Confirmation Effective Date (the “Disclosure Schedule”);

(d)

On the Confirmation Effective Date, the “Historical Outage Report” sets forth true and accurate historical data of (a) the dates during which each Generating Unit (including the Generating Units that will become subject to the obligations of this Confirmation during the Delivery Period) was available to generate Energy during the period from 2009 to the present regardless of whether or not such Generating Unit did in fact generate Energy, and each Generating Unit's capacity to generate Energy for each of those dates during which the Generating Unit was available, and (b) for those dates when each Generating Unit was not available to generate Energy, the reasons for such unavailability; and

(e)

In the event SCE is not the SC, no later than two weeks prior to the first day of the Delivery Period,

20

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Seller shall take all actions necessary with the CAISO and SCE to ensure that by the day immediately prior to the first day of the Delivery Period, the CAISO Master File and, if applicable, the RMR Contract reflect the values that SCE deems appropriate based on the Operating Restrictions under this Confirmation. If, at any time prior to the termination of this Confirmation, any action or inaction of Seller, or a condition of any Generating Unit that could result in a revision to the CAISO Master File or to the operating restrictions set forth in an RMR Contract, then Seller shall promptly give notice to SCE and shall use all reasonable efforts to maintain the Operating Restrictions exactly as they existed on the Confirmation Effective Date.

ARTICLE 14 ELECTRIC SYSTEM RELIABILITY STANDARDS During the Delivery Period, Seller shall be (i) responsible for complying with any NERC Reliability Standards applicable to the Generating Units, including registration with NERC as the Generator Operator for the Generating Units or other applicable category under the NERC Reliability Standards and implementation of all applicable processes and procedures required by NERC, WECC or CAISO for compliance with the NERC Reliability Standards; and (ii) liable for all penalties assessed by NERC (through WECC or otherwise) for violations of the NERC Reliability Standards by the Generating Facility or Seller, as Generator Operator or other applicable category. However, if Seller learns that NERC (through WECC or otherwise) is considering or intends to assess Seller with a penalty that Seller believes is attributable to SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the potential assessment, Seller shall provide SCE with sufficient notice to allow SCE to take part in administrative processes, discussions or settlement negotiations with NERC, WECC or other entity arising from or related to the alleged violation or possible penalty. If the penalty is nonetheless assessed in spite of SCE’s participation in the processes, discussions or settlement negotiations, or SCE waives its right to take part in the processes, discussion or settlement negotiations, SCE shall reimburse Seller for the penalty to the extent that (a) it was solely caused by SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the violation; and (b) Seller can establish to SCE’s reasonable satisfaction that the penalty was actually assessed against Seller by NERC and paid by Seller to NERC. If SCE took part in and agreed to the terms of settlement, SCE shall also reimburse Seller for any payment made by Seller in settlement of a claim of violation by or on behalf of NERC, to the extent that (x) the claim being settled was solely caused by SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the claim; and (y) Seller can establish to SCE’s reasonable satisfaction that Seller actually made the payment to NERC under the settlement.

ARTICLE 15 CREDIT TERMS AND MARK-TO-MARKET VALUE 15.1

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEI Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex: (i) Seller’s Exposure to SCE for this Transaction shall be zero dollars ($0) and (ii) SCE’s Exposure to Seller plus the Independent Amount, if any, for this Transaction shall not exceed three million two hundred thousand dollars ($3,200,000) (unless otherwise defined, capitalized terms in this Article 15 are used with the meanings ascribed to them in the Transition Collateral Annex). 15.2

Independent Amount

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2012 CHP Energy Only UC Toll (Kern Pipeline--linaneially settled gas)

If Seller's Credit Rating is lower than BBB- by S&P, Baa3 by Moody's, or BBB- by Fitch, Seller shall have a Full Floating Independent Amount of the amount equal to ten percent (10%) of the market value of this Transaction. Upon the Confirmation Effective Date and until the start of the Delivery Period the term "market value" shall mean the sum of the Monthly Capacity Payments to be paid under this Transaction for the Delivery Period, and upon the start of the Delivery Period the term "market value" shall mean the sum of the Monthly Capacity Payments for the current month and all remaining months of the Delivery Period to be paid under this Transaction.

15.3

Mark-la-Markel Value

For purposes of determining Exposure for this Transaction, the Parties shall calculate the Current Mark-to-Market Value of this Transaction using the following methodology. On any Calculation Date, the Current Mark-to-Market Value for this Transaction will be calculated by taking the sum of the Present Values for each remaining (full or partial) month prior to the termination of this Transaction using the equation below: Current

MAX

Mark-to-Market

[tl(MV.,; -

M'V",;) x Q, x DF,,;,

=

Value

oj) Er(MII"i .- MV.,,) x Q,

x

D'F"i where:

MV",. = M AX (Po., - Go,; x HR" 0) .

DE',,;

= (:1+r~,}

--(!X~ 365

and: Variable n i

Pt,i

Po,1

Gl,I

Go,1

Description The number of forward months included in the mark-la-market calculalion. A forward month. For the balance of the month of the Calculation Date, i=O. For the month following the month of the Calculation Date, 1=1, etc. The weighted average of Forward Price Assessments for NP15 onpeak and off peak power for the relevanl forward month i on the Calculation Date. If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price calculated from lhe Forward Price Assessments for NP15 on-peak and off-peak power for the last available year. The weighted average of Forward Price Assessments for NP15 onpeak and off-peak power for the relevant forward month i on the Confirmation Effective Date. If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price calculated from the Forward Price Assessments for NP15 on-peak and off-peak power for the last available year. PG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub plus Henry Hub to PG&E City Gate Basis) for the relevant forward monlh i on the Calculation Date. If neither of the aforementioned gas prices are available, then the gas price for the relevant calendar month of the last available year shall be used. PG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub

22

Units

$/MWh

,,-

$/MWh

$/MMBtu

_.$/MMBtu

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

HRi

Qi c d

plus Henry Hub to PG&E City Gate Basis) for the relevant forward month i on the Confirmation Effective Date. If neither of the aforementioned gas prices are available, then the gas price for the relevant calendar month of the last available year shall be used. The Heat Rate associated with the Contract Capacity as specified in Appendix 5.3 of this Confirmation. The Contract Capacity multiplied by the hours remaining under the Transaction for the relevant forward month Interest rate (annualized) Number of compounds per year (e.g. c = 12 if

MMBtu/MWh MW * Hours %

= monthly)

Number of days between calculation date ( ) and payment date.

A positive Current Mark to Market Value implies SCE has the potential for realization of market gains and thus has Exposure to Seller’s default or non-performance. Notwithstanding anything to the contrary contained in the Transition Collateral Annex or this Confirmation, the Parties shall determine the Settlement Amount for this Transaction in accordance with Section 5.2 of the Master Agreement.

ARTICLE 16 ASSIGNMENT In the event of an Assignment permitted under Section 10.5 of the Transition Master Agreement, (i) any such assignee shall agree in writing to be bound by the terms and conditions hereof, (ii) the Collateral Threshold for such assignee shall automatically be deemed to be zero unless the non-assigning Party otherwise agrees, and (iii) the transferring Party must deliver such tax and enforceability assurance as the non-assigning Party may reasonably request. Any assignment in violation of this Article 16 shall be null and void.

ARTICLE 17 CONFIDENTIALITY In addition to the Parties’ obligations under Section 10.11 of the Transition Master Agreement, with respect to this Transaction, Seller agrees that any data, information, or other material Seller receives from SCE or the CAISO pursuant to or in connection with this Confirmation, including any schedules, bids, awards, dispatches, Dispatch Notices, updated Dispatch Notices, settlement statements, Ancillary Services dispatches or awards, or any other information related to the Product (collectively, "Dispatch Data"), shall be confidential to SCE, and Seller shall use such Dispatch Data or other confidential information or material solely in connection with its performance of its obligations under this Confirmation and for no other purpose. Furthermore, Seller shall not disclose this Dispatch Data or other confidential information to any of its employees, personnel, contractors, agents, or consultants who are engaged wholly or in part in the business of marketing or selling wholesale electrical power or natural gas unless such employees, personnel, contractors, agents, or consultants (a) are directly engaged in performing Seller's obligations under this Confirmation, (b) need to know such information in order to perform Seller's obligations under this Confirmation, (c) are informed of (i) the confidentiality of such Dispatch Data and any information governed by this Article 17 and Section 10.11 of the Transition Master Agreement and (ii) the requirements of this Confirmation and the Transition Master Agreement, and (d) are directed to comply with the requirements of this Confirmation and the Transition Master Agreement. Seller agrees that irreparable damage to SCE would occur if Seller were to breach its obligations under this Article 17 and that SCE shall be entitled to all available remedies at law or in equity.

ARTICLE 18 PAYMENT, NETTING AND SETOFF

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Unless otherwise set forth herein, the Parties agree that Sections 5.3, 5.6, and Article Six of the Transition Master Agreement shall apply to this Transaction and that any payment due to or due from either Party to the other Party pursuant to the terms of this Confirmation shall be subject to such provisions.

ARTICLE 19 CALIFORNIA AIR RESOURCES BOARD REPORTING REQUIREMENTS During the Term, Seller shall provide such information SCE deems necessary for SCE to comply with those GHG emissions reporting requirements adopted by the California Air Resources Board (“CARB”), or as Seller is otherwise required to provide by Applicable Law or Governmental Authority.

ARTICLE 20 ENVIRONMENTAL CHARGES 20.1

Indemnification

Seller is solely responsible for all Environmental Costs and, other than as provided in Sections 20.2 through 20.4, all GHG Charges, Seller’s Compliance Obligation, and all other costs associated with the implementation and regulation of Greenhouse Gas emissions (whether in accordance with AB 32 or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions implemented and regulated by an authorized Governmental Authority) with respect to the Generating Unit(s) and/or Seller. Seller shall indemnify, defend and hold SCE harmless from and against all liabilities, damages, claims, losses, costs and/or expenses (including, without limitation, attorneys’ fees) incurred by or brought against SCE in connection with such Environmental Costs, GHG Charges, Compliance Obligation, and such other costs. 20.2

Greenhouse Gas Emissions Compliance Cost

Notwithstanding anything to the contrary in Section 20.1, and subject to Seller’s compliance with Section 20.3, in the event that a Governmental Authority imposes any taxes, charges, or fees on the Generating Unit(s) or Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (collectively, “GHG Charges”), Seller shall provide SCE documentation of such GHG Charges within 90 days of Seller incurring the obligation to pay the GHG Charge and such documentation shall establish to SCE’s reasonable satisfaction (all such documentation identified in subsections (a)-(f) below shall be collectively referred to hereinafter as “GHG Documentation”), that: (a)

Seller is actually liable for the GHG Charges during the Delivery Period;

(b)

the Applicable Law imposing the GHG Charge was (i) not in effect or (ii) not scheduled to become effective and applicable to the Generating Unit(s) as of the Confirmation Effective Date;

(c)

the specific amount of the GHG Charges;

(d)

the GHG Charge was imposed upon Seller by an authorized Governmental Authority in whose jurisdiction the Generating Units are located, or which otherwise has jurisdiction over Seller or the Generating Units;

(e)

Seller has paid the Governmental Authority identified in (d) above the full amount of the GHG Charge for which Seller seeks reimbursement from SCE under this Section 20.2; and

(f)

Seller took all reasonable steps to mitigate the cost or amount of such GHG Charges, including utilizing any GHG Credits or revenues described in Section 20.3(a)(i) below; provided, that the

24

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

reasonable steps shall not be deemed to require Seller to make capital improvements to the Generating Unit. SCE shall reimburse Seller for such GHG Charge within forty-five (45) calendar days of SCE’s receipt of the GHG Documentation. In no event shall SCE be responsible for GHG Charges associated with Greenhouse Gas emissions that exceed the GHG Cap or a Non-SCE Dispatch during the Term. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period. 20.3

Greenhouse Gas Emissions Credits (a)

In the event that, during the Term, Seller is: (i)

allocated or issued, or has the right to obtain, at no cost to Seller other than administrative or overhead costs, allowances, credits, or other similar rights to emit Greenhouse Gas in accordance with a cap-and-trade or any other federal, state or local legislation, other than AB 32, implemented by an authorized Governmental Authority (“GHG Credits”) to offset or reduce any Greenhouse Gas emissions, then Seller shall obtain and utilize such allowances or credits to mitigate any GHG Charge at no cost to Buyer;

(ii)

allocated or issued or has the right to obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for a portion of or its entire fleet of generating units (all or some of the generating units owned, managed, or controlled by Seller that are subject to any Greenhouse Gas legislation, regulation, law or other similar governmental action) (“Seller’s Fleet”), then Seller shall utilize a proportional amount of such allowances or credits to mitigate any GHG Charge at no cost to SCE; or

(iii)

allocated or receives revenues, whether specific to the Generating Unit(s) or Seller’s Fleet, associated with any allowance or credit allocated at no cost to Seller other than administrative or overhead costs and associated with Greenhouse Gas emissions, then Seller shall remit any such revenue or, if allocated to Seller’s Fleet, the proportional amount of such revenue, to SCE to mitigate any GHG Charge.

For purposes of Section 20.3(a)(ii) and (a)(iii) above, the proportional amount of allowances, credits, or revenues, as applicable, shall be calculated based on the method, formula or other similar calculation by which the Governmental Authority used to determine the amount of GHG Credits (“GHG Calculation”) attributable to each Generating Unit compared to the sum of all GHG Calculations for all generating units within Seller’s Fleet. (b)

In the event (i) Seller is not allocated, issued, or granted the right to otherwise obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for the Generating Units pursuant to Section 20.3(a) above; (ii) Seller is not allocated or issued sufficient GHG Credits to offset GHG Charges attributable to the Generating Units; or (iii) a liquid market for GHG Credits develops and is available to purchase GHG Credits to offset the GHG Charges, then SCE may, at its option, either: (1) self-supply GHG Credits for the Generating Unit(s); or (2) provide Notice to Seller directing Seller to purchase GHG Credits sufficient to cover the GHG Charges associated with the Generating Unit(s). If SCE elects to direct Seller to purchase GHG Credits, Seller shall purchase

25

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

the number of GHG Credits set forth in the Notice and SCE shall reimburse Seller for those GHG Credits at the lower of Seller’s cost or the prevailing market price at the time the GHG Credits were obtained. In no event shall either Party purchase GHG Credits from an Affiliate. (c)

All GHG Credits (i) allocated, issued or granted, at no cost to Seller other than administrative or overhead costs, rights to Seller for the Generating Units or (ii) paid for or utilized by SCE shall be the sole and exclusive property of SCE; and any excess GHG Credits (GHG Credits not utilized by SCE under this Confirmation) or revenues resulting from GHG Credits shall be the sole and exclusive property of SCE and shall be retained by SCE.

For purposes of this Section 20.3, all references to “Seller” shall be deemed to include Seller’s parent company, holding company or other entity to which allowances or credits may be or have been allocated to or given rights to obtain, at no cost to such entity other than administrative or overhead costs, for the Generating Units. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period.

20.4

Compensation for Seller’s Compliance Obligation (a)

(b)

If Seller is not eligible for an exemption and subject to Section 20.5, Buyer shall satisfy its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period, in arrears of the creation of such Compliance Obligation, by: (i)

Providing to Seller the Allowances and/or the Offset Credits that will permit Seller to satisfy the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, as further described in Section 20.4(b);

(ii)

Paying to Seller the GHG Compliance Costs for the Delivery Period, as further described in Section 20.4(c); or

(iii)

Utilizing any combination of the compensation methods described in Sections 20.4(b) and 20.4(c), such that Buyer shall fulfill its obligation to compensate Seller for the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period by providing Allowances, Offset Credits and/or the GHG Compliance Costs.

If Buyer, in its sole discretion, elects to provide Seller with Allowances and/or Offset Credits, then Buyer shall, at any time (or from time to time) after Buyer has received the data for calculating the Required Natural Gas Quantity that allows Buyer to calculate Seller’s compensation for any portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, and pursuant to one or more conveyances of Allowances and/or Offset Credits, convey and deliver to Seller, either electronically or otherwise, such Allowances and/or Offset Credits; provided that: (i)

Buyer must transfer such Allowances and/or Offset Credits in a timely manner so as to permit Seller to satisfy the Compliance Obligation imposed on Seller during the Delivery Period (including, without limitation, Seller’s annual compliance obligation, as described in Section 95855 of the GHG Regulations);

26

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

(ii)

Upon each conveyance and delivery of such Allowances and/or Offset Credits by Buyer to Seller, Seller shall take all actions to accept delivery of such Allowances and/or Offset Credits such that the conveyed Allowances and/or Offset Credits shall have transferred from Buyer’s account to Seller’s account in accordance with the GHG Regulations;

(iii)

Buyer may, in its sole discretion, reduce the number of Allowances it delivers to Seller pursuant to this Section 20.4(b) by some or all of the Free Allowances that are deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s) and to the extent not applied to a prior conveyance and delivery of Allowances by Buyer to Seller under this Confirmation;

(iv)

The amount of Offset Credits that Buyer conveys and delivers to Seller throughout the Delivery Period (if any) will not exceed the Quantitative Usage Limit for the total Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period; and

(v)

No later than three (3) Business Days before Buyer conveys and delivers such Allowances and/or Offset Credits to Seller, and also on each of Transfer Date 1, Transfer Date 2 and Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period), Buyer shall deliver a notice to Seller (the “Transfer Notice”), which Transfer Notice shall inform Seller of: (1)

The number of Allowances and/or Offset Credits that Buyer has conveyed and delivered to Seller pursuant to any previous Transfer Notices, and the time-period during the Delivery Period for which such Allowances and/or Offset Credits applied;

(2)

The number of Allowances and/or Offset Credits that Buyer shall convey and deliver to Seller pursuant to the subject Transfer Notice, and the time-period during the Delivery Period for which such Allowances and/or Offset Credits shall apply;

(3)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Transfer Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(4)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Transfer Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(5)

The date on which Buyer shall convey and deliver such Allowances and/or Offset Credits pursuant to the subject Transfer Notice;

(6)

The number of Free Allowances deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s), which Buyer shall deduct from Buyer’s compensation of Seller to the extent such Free Allowances have not been applied to a prior conveyance and delivery of Allowances by Buyer to Seller pursuant to a Transfer Notice under this Confirmation; and

(7)

The information set forth in Section 20.4(c)(i) through (vi), if Buyer has determined to compensate Seller in part by paying to Seller the GHG Compliance Costs in accordance with Section 20.4(c).

27

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

(c)

If Buyer, in its sole discretion, elects to compensate Seller by paying to Seller the GHG Compliance Costs, then Buyer (x) shall deliver a notice to Seller on or before Transfer Date 1, Transfer Date 2 and/or Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period) (such notice, the “Required Payment Notice”), and (y) may, in its sole discretion, deliver a notice to Seller on or before any Optional Transfer Date (such notice, the “Optional Payment Notice”), which Required Payment Notice and Optional Payment Notice shall inform Seller of: (i)

Buyer’s intent to pay to Seller such GHG Compliances Costs;

(ii)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Required Payment Notices and Optional Payment Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(iii)

The time-period during the Delivery Period for which Buyer has compensated Seller pursuant to any previous Required Payment Notices or Optional Payment Notices;

(iv)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(v)

The time-period during the Delivery Period for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice; and

(vi)

The date of the upcoming Auction pursuant to which the Auction Settlement Price necessary to calculate the GHG Compliance Costs will be based.

After (1) Seller receives such Required Payment Notice or Optional Payment Notice, and (2) the Auction Settlement Price necessary to calculate such GHG Compliance Costs is published, Seller shall calculate and include as part of the upcoming single regular monthly invoice to Buyer under this Confirmation (and in no event as an invoice that is separate or distinct from such regular monthly invoice), such GHG Compliance Costs. After Buyer’s receipt of such invoice, Buyer shall pay such GHG Compliance Costs along with all other payments due under such invoice in accordance with Article 6 of the Transition Master Agreement. (d)

Seller shall deliver to Buyer a Free Allowance Notice within twenty (20) calendar days of Seller or the Generating Unit(s) being allocated any Free Allowances (with such allocation being determined in accordance with the requirements of subparagraphs (i) or (iv) of the definition of Free Allowance Notice, as applicable, including, without limitation, the requirement that some or all of an allocation of Free Allowances to Seller’s Affiliates shall, if applicable, be deemed to be allocated to Seller). Notwithstanding anything to the contrary set forth in this Section 20.4, to the extent not previously applied, Buyer shall have the right to apply such Free Allowances or the value thereof (as disclosed in the Free Allowance Notice(s)), as applicable, in order to reduce Buyer’s compensation of Seller pursuant to Section 20.4(b) and/or Section 20.4(c) at any time during the Term regardless of when such Free Allowances are allocated (or deemed allocated) to Seller.

(e)

Seller acknowledges and agrees that: (i)

Upon Buyer’s conveyance and delivery of Allowances and/or Offset Credits in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)) or Buyer’s payment to Seller of the GHG Compliance Costs in accordance with Section 20.4(c), or any

28

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

combination thereof, Buyer shall have fulfilled its obligation under this Confirmation to compensate Seller for the Compliance Obligation deemed imposed on Seller with respect to the Generating Unit(s) during the applicable time-periods set forth in the Transfer Notice(s), Required Payment Notice(s) and/or Optional Payment Notices, and that Buyer is not in any way liable for Seller’s failure to satisfy its Compliance Obligation or otherwise comply with AB 32 or the GHG Regulations; and (ii)

20.5

Title to, and risk of loss, invalidation, cancellation or removal of each Allowance and/or Offset Credit conveyed and delivered to Seller by Buyer (including, without limitation, any such loss, invalidation, cancellation or removal of an Allowance and/or Offset Credit as a result of an action by an authorized Governmental Authority in accordance with the GHG Regulations) transfers from Buyer to Seller upon Buyer’s conveyance and delivery to Seller of each such Allowance and/or Offset Credit in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)); provided that, if (1) any Offset Credits transferred by Buyer to Seller are invalidated pursuant to the GHG Regulations after the date of such transfer, (2) Seller has not sold or otherwise transferred such Offset Credits to a third party, other than to the Governmental Authority or other entity authorized to implement the regulatory program on behalf of the Governmental Authority in satisfaction of Seller’s compliance obligation (a “Compliance Transfer”), and (3) except in the case of a Compliance Transfer, Seller demonstrates to Buyer’s reasonable satisfaction that it retains title to such invalidated Offset Credits, then to the extent such Offset Credits or other compliance instruments are still required in order for Seller to satisfy the original compliance obligation for which the Offset Credits were transferred by Buyer to Seller, Buyer shall compensate Seller in accordance with and subject to Sections 20.4 through 20.9 for such invalidated Offset Credits to the extent necessary for Buyer to have satisfied, with respect to such invalidated Offset Credits, its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period.

Limitation of Liability

Notwithstanding anything to the contrary in the Agreement, Buyer is not responsible for:

20.6

(a)

Any Compliance Obligation imposed on Seller or the Generating Unit(s), providing any Allowances and/or Offset Credits, or paying any GHG Compliance Costs, to the extent any or all of the aforementioned are associated with Greenhouse Gas emissions that exceed the GHG Cap, that occur outside of the Delivery Period, and/or that result from a Non-SCE Dispatch;

(b)

Any taxes, fees and/or other charges implemented by and imposed upon Seller or the Generating Unit(s) pursuant to Title 17 of the California Code of Regulations, Section 95200, et. seq. (AB 32 Cost of Implementation Fee Regulation), or any similar taxes, charges and/or fees imposed on the Generating Unit(s) or Seller; or

(c)

Any taxes, fees, charges and/or other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to any generating unit that is not a Generating Unit.

Greenhouse Gas Compliance Covenants (a)

Seller covenants that (i) from the commencement of the Delivery Period until the end of the Term, it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation and (ii) throughout the Term, it shall comply with all requirements applicable to Seller and/or the Generating Unit(s) under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation.

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(b)

20.7

Buyer covenants that (i) from the commencement of the Delivery Period until the end of the Term it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation, (ii) throughout the Term, it shall comply with all requirements applicable to Buyer under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation, (iii) it shall convey and deliver the Allowances and/or Offset Credits to Seller free from all liens, claims, security interests and defects in title, (iv) each Allowance and/or Offset Credit conveyed and delivered to Seller pursuant to this Confirmation (1) will be, at the time it is conveyed and delivered, validly issued and in force in accordance with the GHG Regulations, and will have been assigned a Vintage Year (as defined in the GHG Regulations) that allows it to be retired during the applicable Compliance Period in accordance with the GHG Regulations, and (2) may be utilized by Seller for compliance with AB 32 and/or the GHG Regulations then in effect, (v) it will have, at the time conveyed and delivered good and marketable title to each Allowance and/or Offset Credit conveyed and delivered to Seller, and that it will obtain and possess at the time conveyed and delivered, each such Allowance and/or Offset Credit lawfully.

Liquid Market for Allowances

If, at any time before the expiration of the Delivery Period, a liquid market for Allowances develops wherein price quotes for Allowances can be obtained, the Parties agree to work in good faith to amend this Confirmation to include a methodology for calculating the GHG Compliance Costs for this Transaction using such price quotes. 20.8

Suspension, Repeal or Supersedence of AB 32; Change in AB 32

Notwithstanding anything to the contrary in the Agreement, if AB 32 is suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then, as of the effective date of such suspension, repeal or supersedence, Sections 20.4 through 20.8 will no longer be in force or effect on a going forward basis; provided that subject to and in accordance the terms of the Agreement, Buyer shall be liable to Seller for compensating Seller for Seller’s Compliance Obligation, if any, imposed on Seller for the Generating Unit(s) before such suspension, repeal or supersedence. To the extent Buyer has provided compensation to Seller pursuant to Sections 20.4(b) and 20.4(c) to cover an expected Compliance Obligation under AB 32 and that obligation is subsequently suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then Seller shall return any such compensation in a timely manner to Buyer. If a Change in AB 32 occurs, then either Party, on notice, may request the other Party to enter into negotiations to make the minimum changes to this Confirmation necessary to preserve to the maximum extent possible the balance of benefits, burdens and obligations set forth in this Confirmation as of the Confirmation Effective Date. Upon receipt of a notice requesting negotiations, the Parties shall negotiate in good faith. If the Parties are unable, within sixty (60) days after the sending of the notice requesting negotiations, either to agree upon changes to this Confirmation or to resolve issues relating to changes to this Confirmation, then either Party may submit issues pertaining to changes to this Confirmation to dispute resolution as provided in Section 10.6 of the Transition Master Agreement. In addition to any notices provided above, Seller shall provide notice to SCE as soon as practicable in the event that Seller believes a Change in AB 32 has occurred. 20.9

Exposure Calculation (a)

Subject to any restrictions set forth in the Agreement (including, without limitation, Section 15.1 and Section 20.5 of this Confirmation), the Parties agree that for purposes of calculating Seller’s Exposure to Buyer in respect of a Transaction under the Confirmation, such calculation shall include Buyer’s obligation to compensate Seller for the Compliance Obligation imposed on Seller for the Generating Unit(s) during the Delivery Period to the extent that such obligation is owed or

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APPENDIX A DEFINITIONS UNLESS OTHERWISE DEFINED IN THE TRANSITION MASTER AGREEMENT AND ATTACHMENTS, CAPITALIZED TERMS SHALL BE USED WITH THE MEANINGS ASCRIBED TO THEM IN THE TARIFF. AB 32: The California Global Warming Act of 2006, Assembly Bill 32 (2006) and the regulations promulgated thereunder (including, without limitation, the GHG Regulations) by any authorized Governmental Authority. Accepted Electrical Practices: Those practices, methods, applicable codes, and acts engaged in or approved by a significant portion of the electric power industry during the relevant time period, or any of the practices, methods, and acts which, in exercise of reasonable judgment in light of the facts known at the time a decision is made, could have been expected to accomplish a desired result at reasonable cost consistent with good business practices, reliability, safety, and expedition. Accepted Electrical Practices are not intended to be limited to the optimum practices, methods, or acts to the exclusion of other, but rather to those practices, methods, and acts generally accepted, or approved by a significant portion of the electric power industry in the relevant region, during the relevant time period, as described in the immediately preceding sentence. Adjustment Gas Cost: As set forth in Section 3.1(d)(viii) of this Confirmation. Adjustment Gas Quantity: As set forth in Section 3.1(d)(v) of this Confirmation. ADS: The Automatic Dispatch System, or its successor. Air Pollution Control District: A district as defined by Section 39025 of the California Health and Safety Code, Division 26, Air Resources. Allowance: (i) CA GHG Allowance, as such term is defined in the GHG Regulations, or (ii) an allowance specified in Section 95942(b) of the GHG Regulations and approved by the CARB pursuant to Section 95941 of the GHG Regulations. Ancillary Services: As set forth in the Tariff. Ancillary Services Capacity: For each applicable Ancillary Service, the Ancillary Service available to SCE within the scope of operations allowed SCE under this Confirmation pursuant to Section F of Appendix 1.4, plus any other interconnected operation services that the CAISO develops or deems as Ancillary Services. Applicable Laws: Means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Authority having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. A/S Availability: The amount of Ancillary Services Capacity available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. A/S Maximum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the maximum capacity for a particular region in which such Ancillary Service is available. A/S Minimum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the minimum capacity for a particular region in which such Ancillary Service is available.

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Auction: Each auction for Allowances conducted in accordance with Subarticle 10 of the GHG Regulations, except for the first auction identified in Section 95910(a)(1) of the GHG Regulations. Auction Settlement Price: As set forth in the GHG Regulations. Automatic Generation Control or AGC: output.

The remote signal control of a Generating Unit’s megawatt

Availability Incentive Payments: As set forth in the Tariff. Availability Notice: As set forth in Section 9.1 of this Confirmation. Availability Standards: As set forth in the Tariff. Available Capacity: The amount of Contract Capacity that is available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. If a Generating Unit’s Available Capacity during any Settlement Interval is below PMin, then the Available Capacity shall be deemed zero for such Settlement Interval. Black Start: As set forth in the Tariff. Boiler or Boiler Unit: Conventional steam cycle. CAISO: The California Independent System Operator or any successor entity performing the same functions. CAISO Grid: The system of transmission lines and associated facilities of the Participating Transmission Owners that have been placed under the CAISO’s operational control. Capacity: Exclusive of any Resource Adequacy Benefits, the maximum dependable operating capability of any generating resource to produce or generate Energy and any other products that may be developed or evolve from time to time that relate to the capability of a generating resource to produce or generate Energy. Capacity Availability: For each Settlement Interval (i) the Generating Unit’s Available Capacity, if the Generating Unit operates within the Performance Tolerance Band, or (ii) the Generating Unit’s Available Capacity, less the product of (x) the difference between (a) Scheduled Energy minus (b) Qualifying Delivered Energy, and (y) the number of Settlement Intervals in one hour, if the Generating Unit operates below the Performance Tolerance Band Lower Limit. In no event shall the Capacity Availability be less than zero MW nor greater than the Contract Capacity for the Generating Unit. CARB: California Air Resources Board, or any successor entity. CCGT: Combined cycle gas turbine. Change in AB 32: A change in AB 32 after the Confirmation Effective Date, which change has a material impact on either party with respect to a Compliance Obligation under Article 20 with respect to the electric energy produced, sold or purchased pursuant to this Confirmation. A Change in AB 32 may include, for example, a change in exemptions or the calculation of compliance obligations, but will not include an increase or decrease in the cost of Allowances or Offset Credits. CHP: As set forth in Article 5 of this Confirmation. Compliance Obligation: As set forth in the GHG Regulations.

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Compliance Period: As set forth in the GHG Regulations. Compliance Transfer: As set forth in Section 20.4(e)(ii) of this Confirmation. Contract Capacity: As set forth in Section A of Appendix 1.4 of this Confirmation, the Quantity of Capacity that Seller is committing to provide to SCE pursuant to this Confirmation. Contract Year: The twelve (12) months within each calendar year starting with the beginning of the Delivery Period until the termination of this Confirmation. CPUC: The California Public Utilities Commission or any successor thereto. CPUC Approval: Means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of this Confirmation, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. Crossing Time: Forbidden Region Crossing Time, as set forth in the “Definition” tab of the CAISO Master File. CT: Combustion turbine. Day-Ahead Gas Cost: As set forth in Section 3.1(d)(vii) of this Confirmation. Day-Ahead Gas Quantity: As set forth in Section 3.1(d)(iv) of this Confirmation. Delivered Energy: With respect to a Generating Unit and during the Delivery Period, the amount of Energy generated by such Generating Unit and delivered during each Settlement Interval at the Energy Delivery Point as measured by the Energy Metering Equipment, and subject to adjustments identified in this Confirmation. The Delivered Energy in any hour is equal to the sum of the Delivered Energy for each Settlement Interval during such hour. Delivery Period: Has the meaning specified in Section 1.4 of this Confirmation. Disclosure Schedule: As set forth in Section 13.3(c) of this Confirmation. Dispatch Data: As set forth in Article 17 of this Confirmation. Dispatch Notice: The operating instruction, and any subsequent updates given by SCE to Seller, directing the applicable Generating Unit to operate at a specified megawatt output or a dispatch given by the CAISO under Section 9.3. Dispatch Notices may be communicated electronically (i.e., through ADS), via e-mail, via facsimile, telephonically, or by other verbal means. Telephonic or other verbal communications shall be documented (either recorded by tape, electronically or in writing) and such recordings shall be made available to both SCE and Seller upon request for settlement purposes. Distributed Control System or DCS: The integrated automation system for monitoring and controlling the critical operation functions of a facility that performs tasks essential to the generation of electricity. Emission Reduction Credits or ERC(s): Emission reductions that have been authorized by a local air pollution control district pursuant to California Division 26 Air Resources; Health and Safety Code Sections 40709 and 40709.5, whereby a district has established a system by which all reductions in the

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emission of air contaminants that are to be used to offset certain future increases in the emission of air contaminants shall be banked prior to use to offset future increases in emissions. Energy: All electrical energy produced, flowing, or supplied by a Generating Unit less the Station Use, measured in kilowatt-hours or multiples units thereof. Energy shall include without limitation any energy associated with Capacity, Ancillary Services, and any other electrical energy product that may be developed or evolve from time to time during the Term. Energy Delivery Point: The point on the CAISO grid defined in Appendix 1.6 of this Confirmation. Energy Metering Equipment: For each Generating Unit, the meters and measuring equipment certified by the CAISO for such Generating Unit, and which measures the Delivered Energy of such Generating Unit. Environmental Costs: Costs incurred in connection with acquiring and maintaining all environmental permits and licenses for the Generating Units, and the Generating Unit’s compliance with all applicable environmental laws, rules and regulations, including capital costs for pollution mitigation or installation of emissions control equipment required to permit or license the Generating Units, all operating and maintenance costs for operation of pollution mitigation or control equipment, costs of permit maintenance fees and emission fees as applicable, and the costs of all Emission Reduction Credits or Marketable Emission Trading Credits required by any applicable environmental laws, rules, regulations, and permits to operate, and costs associated with the disposal and clean-up of hazardous substances introduced to the Generating Unit site, and the decontamination or remediation, on or off the Generating Unit site, necessitated by the introduction of such hazardous substances on the Generating Unit site. Exposure: As set forth in the Transition Collateral Annex. Failed Test: As set forth in Section 10.2 of this Confirmation. FERC Approval: Means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at marketbased rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. Final Test Plan: As set forth in Appendix 10.2 of this Confirmation. Forbidden Operating Region: As set forth in the Tariff. Forced Outage: As set forth in the Tariff. Free Allowance: Authority.

Any Allowance freely allocated by the CARB or another authorized Governmental

Free Allowance Notice: The notice delivered by Seller to Buyer in accordance with Section 20.4(d), which notice shall set forth: (i) The aggregate quantity of Free Allowances allocated by the CARB (and/or any other Governmental Authority) to Seller, any of Seller’s Affiliates, and/or the Generating Unit(s) for Greenhouse

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Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof); and (ii) Any documentation from the CARB (and/or any other Governmental Authority) relating to such allocation. If the CARB (and/or any other Governmental Authority) allocates Free Allowances to Seller (and/or any of Seller’s Affiliates), but does not specifically allocate such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), then the notice described in this definition shall set forth: (iii) The aggregate quantity of Free Allowances allocated to Seller and/or any of Seller’s Affiliates by the CARB (and/or any other Governmental Authority), and all documentation from the CARB (and/or any other Governmental Authority) relating to such allocation; (iv) The number of Free Allowances that shall be deemed allocated to Seller and/or the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), which number Seller shall calculate: (1) By utilizing the then-effective methodology established by the CARB (and/or any other Governmental Authority) relating to such allocation, including, without limitation, any methodology that would apportion a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, Covered Entities and/or Opt-in Covered Entities (as each term is defined in the GHG Regulations)) that could be allocated such Free Allowances; or (2) If the CARB (and/or other Governmental Authority) has not established such a methodology, by apportioning a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, oil refineries and/or other industrial process plants) that could be allocated such Free Allowances; and (v) All documentation reasonably necessary to support the methodology set forth in subparagraph (iv)(1) and/or (iv)(2) of this definition, which shall include, without limitation, any documentation reasonably requested by Buyer to verify Seller's methodology and calculations after Buyer’s receipt of such notice. Fuel Payment: As set forth in Section 3.1(d) of this Confirmation. Full Floating Independent Amount: As set forth in Section 15.2 of this Confirmation. Full Load: As set forth in Appendix 10.2 of this Confirmation. GADS: The Generating Availability Data System, or its successor. Gas Commodity Costs: As set forth in Section 3.1(d)(vi) of this Confirmation. Gas Day: As defined in the applicable tariff of the gas transporter supplying the Generating Unit. Gas Index: As defined in Section 3.1(d)(i) of this Confirmation. Gas Trading Day: As set forth in Section 3.1(d)(ii) of this Confirmation.

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Generating Facility: Power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. The Generating Facility shall include the Generating Units. Generating Unit: The generating unit or units specified in Appendix 1.8 of this Confirmation. References to Generating Units shall be applicable only to Generating Unit # 1 and Generating Unit # 3 throughout the Delivery Period. Generating Unit # 1: The Generating Unit described in Section 1.a. of Appendix 1.8 of this Confirmation. Generating Unit # 3: The Generating Unit described in Section 1.b. of Appendix 1.8 of this Confirmation. Generation Operations Center or GOC: The location of SCE’s Real Time operations personnel. Generation Management System or GMS: The automated system employed by SCE real time operations to remotely monitor, dispatch, and control each Generating Unit. Generator Operator: The entity that operates the Generating Unit(s) and performs the functions of supplying energy and interconnected operations services as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. Generator Owner: The entity that owns and maintains the Generating Unit(s) as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. GHG Calculation: As set forth in Section 20.3 of this Confirmation. GHG Cap: The GHG Rate times the Required Natural Gas Quantity associated with a Dispatch Notice. GHG Charges: As set forth in Section 20.2 of this Confirmation. GHG Compliance Cost: The dollar amount calculated by multiplying: (i) The cost of one Allowance, determined using the published Auction Settlement Price from the last Auction to have taken place before the date that Buyer’s payment is due to Seller in accordance with Section 20.4(c); by (ii) The number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) during the applicable time-period, which number is determined by multiplying the GHG Rate by the Required Natural Gas Quantity for each calendar day during the applicable time-period; provided that if Buyer determines to compensate Seller for a portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) by providing Seller with Allowances and/or Offset Credits in accordance with Section 20.4(b), the factor set forth in this subparagraph (ii) will be reduced by the number of metric tons of Greenhouse Gas emissions (rounded up to the nearest metric ton) for which Buyer provides such Allowances and/or Offset Credits. GHG Credits: As set forth in Section 20.3(a)(i) of this Confirmation. GHG Documentation: As set forth in Section 20.2 of this Confirmation. GHG Rate: The rate for pounds of Greenhouse Gas emissions per MMBtu of natural gas, 117 lbs of Greenhouse Gas emissions /MMBtu, as derived through information provided in the Energy Information Administration’s Documentation for Emissions of Greenhouse Gases in the United States 2005 (DOE/EIA-0638) http://www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2005).pdf and the Environmental Protection Agency’s Emission Factors, AP 42, Fifth Edition, Volume I http://www.epa.gov/ttn/chief/ap42/index.html.

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GHG Regulations: Subchapter 10 Climate Change, Article 5, Sections 95800 to 96022, Title 17, California Code of Regulations, as amended or supplemented from time to time. Governmental Authority: Any federal, state, local, municipal, or other governmental, executive, administrative, judicial, or regulatory entity, and the CAISO or any other transmission authority, having or asserting jurisdiction over a Party, any Generating Unit or this Confirmation. Green Attributes: Any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1

(3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. Greenhouse Gas: As set forth in the GHG Regulations. 1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program.

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Heat Rate: The amount of natural gas in MMBtu required to produce one MWh of Energy. Historical Outage Report: As set forth in Section 13.3(d) of this Confirmation. Holiday: New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, or Christmas Day. When any Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. Host Site: The site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Affiliates located at such site. IE: As set forth in Section 13.2(b) of this Confirmation. IFA or Interconnection Facilities Agreement: Any agreement between the Seller and its Participating Transmission Owner providing for the transmission of electrical energy from the Generating Unit to the point of interconnection. IFM or Integrated Forward Market: As set forth in the Tariff. Industry Standards: As set forth in Section 13.1 of this Confirmation. Lower MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Marketable Emission Trading Credits: Without limitation, emissions trading credits or units pursuant to the requirements of California Division 26 Air Resources; Health & Safety Code Section 39616 and Section 40440.2 for market based incentive programs such as the South Coast Air Quality Management District’s Regional Clean Air Incentives Market, also known as RECLAIM, and allowances of sulfur dioxide trading credits as required under Title IV of the Federal Clean Air Act (see 42 U.S.C. § 7651b.(a) to (f)). Master File: As set forth in the Tariff. Maximum Daily Start-Ups: As set forth in the Tariff. MCP or Market Clearing Price: For each Settlement Interval, the Day-Ahead Market price for the hour in which such Settlement Interval falls for the SP15 EZ Gen Hub. Minimum Down Time: As set forth in the Tariff. Minimum Load: As set forth in the Tariff. Minimum Run Time: As set forth in the Tariff. Monthly Capacity Payment: As set forth in Appendix 3.1(a), but subject to Article 3 of this Confirmation. MSA or Meter Service Agreement: Scheduling Coordinator Meter Service Agreement. Natural Gas Requirements: All of the Generating Unit’s natural gas requirements, including the Required Natural Gas Quantity, natural gas for any Non- SCE Dispatch and natural gas for any other purpose. NERC/GADS Protocols: The GADS protocols established by NERC, as may be updated from time to time. NERC Holidays: “Additional Off-peak Days” as defined by NERC on the NERC website at http://www.nerc.com.

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NERC Reliability Standards: Those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by NERC and approved by the applicable regulatory authorities and available on the NERC website. Non-Availability Charges: As set forth in the Tariff. Non-SCE Dispatch: A dispatch by Seller either (a) pursuant to a Seller Initiated Test or (b) as required by Applicable Laws. Non-Spinning Reserve: As set forth in the Tariff. Offset Credit: As set forth in the GHG Regulations. Operating Day: A day within the Delivery Period on which the Generating Unit operates. Operating Level: As set forth in the “Definition” tab of the CAISO Master File. Operating Reserve Ramp Rate: As set forth in the Tariff. Operating Restriction: Limitations on SCE’s ability to schedule and use Capacity, Ancillary Services, and Energy for each Generating Unit subject to this Confirmation that are identified in Appendix 1.4. Operational Ramp Rate: As set forth in the Tariff. Optional Payment Notice: As set forth in Section 20.4(c). Optional Transfer Date: The first (1st) Business Day of the month in which an Auction during the Delivery Period takes place, not including Transfer Date 2 or Transfer Date 3. Outage: As set for in the Tariff. Outage Management System: As set forth in Section 9.1 of this Confirmation. Outage Schedule: As set forth in Section 11.1 of this Confirmation. Pacific Prevailing Time or PPT: Pacific Daylight Time when California observes Daylight Savings Time and Pacific Standard Time otherwise. Participating Transmission Owner: A transmission owner which has released operational control of its transmission facilities to the CAISO. Performance Tolerance Band: The higher of (a) three percent (3%) of a Generating Unit’s PMax divided by the number of Settlement Intervals in an hour, (b) five (5) MW divided by the number of Settlement Intervals in an hour, or (c) the applicable Regulation Award divided by the number of Settlement Intervals in an hour. If, at any time, the CAISO implements changes to the Performance Tolerance Band, then the Parties agree to negotiate in good faith to amend this definition to maintain the economic benefits and burdens contemplated under this Confirmation. Performance Tolerance Band Lower Limit: A quantity of Energy determined for a Settlement Interval equal to Scheduled Energy minus the Performance Tolerance Band. Performance Tolerance Band Upper Limit: A quantity determined for a Settlement Interval equal to Scheduled Energy plus the Performance Tolerance Band. Permit Requirements:

Any requirement or limitation imposed as a condition of a permit or other

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

authorization relating to construction or operation of the Generating Units subject to the obligations of this Confirmation or related facilities, including limitations on any pollutant emissions levels, limitations on fuel combustion or heat input throughput, limitations on operational levels or operational time, limitations on any specified operating constraint, requirements for acquisition and provision of any Emission Reduction Credits or Marketable Emission Trading Credits; or any other operational restriction or specification related to compliance with any Applicable Laws. PGA or Participating Generator Agreement: As set forth in the Tariff. Planned Outage: As set forth in the applicable CPUC Decisions, namely a planned, scheduled, or any other Outage for the routine repair or maintenance of the Generating Units, or for the purposes of new construction work, and does not include any Outage designated as either forced or unplanned as defined by the CAISO or NERC/GADS Protocols. PMax: As defined in the Tariff. The value of PMax is specified in Appendix 1.4 of this Confirmation. PMin: Minimum Load. Power Rating: The electrical power output value indicated on the generating equipment nameplate. Present Value: The value on a given date of a future payment or series of future payments, discounted using the appropriate yield curve based on the U.S. Treasury constant maturities securities as posted by the Federal Reserve in their H.15 daily update at the following address: http://www.ustreas.gov/offices/domestic-finance/debt-management/interest-rate/yield.html. Product: As set forth in Section 1.5 of this Confirmation. Project: The Generating Facility. Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Protective Apparatus: The control devices (such as meters, relays, power circuit breakers and synchronizers) specified in the Interconnection Facilities Agreement for the Generating Unit. PTC 22: The performance test code entitled “PTC-22-2005 - Gas Turbines," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PTC 46: The performance test code entitled “PTC 46-1996 - Overall Plant Performance," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PURPA: The Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. Qualifying Delivered Energy: The lesser of Delivered Energy or the Performance Tolerance Band Upper Limit for each Settlement Interval during the Delivery Period. Qualifying Delivered Energy shall be zero (0) (i) during a Seller Initiated Test; (ii) during a Non-SCE Dispatch; (iii) if the Delivered Energy is less than PMin minus the Performance Tolerance Band; or (iv) during a Start-Up. Qualifying Facility: An electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of self-certification pursuant to 18 CFR Part 292.207(a).

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Quantitative Usage Limit: As set forth in the GHG Regulations. Reduced Monthly Capacity Payment: As set forth in Section 3.2(c) of this Confirmation. Regulation Award: For each Settlement Interval, shall mean either (i) with respect to the Performance Tolerance Band Upper Limit, the greater of the fifteen-minute HASP Regulation Up awards for the period within such Settlement Interval falls, or (ii) with respect to the Performance Tolerance Band Lower Limit, the greater of the fifteen-minute HASP Regulation Down awards for the period within such Settlement Interval falls. Regulation Down: As set forth in the Tariff. Regulation Ramp Rate: As set forth in the Tariff. Regulation Up: As set forth in the Tariff. Renewable Energy Credit: As set forth in Public Utilities Code Section 399.12(h), as may be amended from time to time or as further defined or supplemented by applicable law. Repair Plan: As set forth in Section 13.2(b) of this Confirmation. Required Natural Gas Quantity: As set forth in Section 3.1(d)(iii) of this Confirmation. Required Payment Notice: As set forth in Section 20.4(c). Resource Adequacy Benefits: The rights and privileges attached to any generating resource that satisfy any entity’s resource adequacy obligations or requirements under any CPUC Decisions 04-01-050, 0410-035, 05-10-042, 06-04-040, 06-06-064, 06-07-031, and 07-06-029 and/or any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable Governmental Authority, as such decisions, rulings, laws, rules, or regulations may be amended or modified from time to time. Resource Adequacy Resource: As set forth in the Tariff. RMR Settlement Coordinator: As set forth in Section 7.2 of this Confirmation. RMR Invoice: As set forth in Section 7.2 of this Confirmation. RMR Revenue: As set forth in Section 7.2 of this Confirmation. Satellite Communications System or SCS: A system provided to Seller by SCE at SCE’s cost for emergency voice communications between SCE and Seller’s operating staff for the Generating Units. SCE Annual Test: As set forth in Section 10.2 of this Confirmation. SCE Dispatched Test: As set forth in Section 10.1 of this Confirmation. SCE Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Scheduled Energy: The Energy from a Generating Unit expected to be delivered during each Settlement Interval to the Energy Delivery Point pursuant to (a) the latest Dispatch Notice, or (b) any CAISO instructions during the Delivery Period, including (i) supplemental energy bids or (ii) Ancillary Services exercised. If, in any Settlement Interval, the expected energy normally published by CAISO is

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

unavailable, incomplete, or does not conform to the Operating Restrictions of the Generating Units, then for settlement purposes for that Settlement Interval only, the Scheduled Energy shall be deemed to be the Delivered Energy. Scheduling Coordinator or SC: As set forth in the Tariff. SC Replacement Date: As set forth in Section 6.4 of this Confirmation. SDD Administration Charge: As set forth in Section 8.4 of this Confirmation. SDD Admin Price: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term as defined in the Tariff. SDD Charge: A scheduling and delivery deviation charge as set forth in Section 8.3 of this Confirmation. SDD Price: For each Generating Unit, the Resource-Specific Settlement Interval LMP (as defined in the MRTU's Tariff Appendix A – “Definitions”) or any equivalent price under MRTU. In no case shall the SDD Price be less than zero (0). Self-Schedule: As set forth in the Tariff. Seller Initiated Test: As set forth in Section 10.1 of this Confirmation. Seller’s Fleet: As set forth in Section 20.3(a)(ii) of this Confirmation. Seller’s Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Settlement Agreement: The Qualifying Facility and Combined Heat and Power Program Settlement Agreement approved by the CPUC in Decision 10-12-035 issued on December 21, 2010, effective November 23, 2011. Settlement Interval: As set forth in the Tariff. Shape: As set forth in Appendix 14 of this Confirmation. Shaped Price: Confirmation.

Shall be the price of power as determined in accordance with Appendix 14 of this

Site Host: The person or persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating Units and the generating units that are subject to the obligations in the Transition PPA. Site Host Load: The electric energy and capacity produced by or associated with the Generating Units and the generating units that are subject to the obligations in the Transition PPA that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b). Site Specific Reference Conditions: Shall have the meaning specified in Appendix 10.2 SP15: The SP15 EZ Gen Hub. If the SP15 EZ Gen Hub (under any name) is not established as part of a market redesign that is implemented after the commencement of the Term, an alternative trading zone may be mutually agreed upon by the Parties in good faith that reasonably approximates the characteristics of the Existing Zone region of SP15. SP15 EZ Gen Hub: As set forth in the Tariff.

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Spinning Reserve: As set forth in the Tariff. Start-Up: Resulting only from a Dispatch Notice, the action of bringing the Generating Unit from shut down status to synchronization with the grid, attainment of its PMin, and the availability of unconditional release of such Generating Unit ready for ramping to the applicable dispatch instruction. Start-Up Aux Energy: The applicable amount of energy (MWh) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Aux Charge: The product of the applicable Start-Up Aux Energy and the sum of the “energy charge” rates (under the column headers “Delivery Service” and “Generation”) set forth in PG&E Tariff Rate Schedule S for “Standby Service at Transmission Service Voltage”] applicable to the appropriate “peak” period and in effect at the time of the applicable Start-Up. If a Start-Up falls within multiple “peak” periods (on-peak, mid-peak, or off-peak), then the Start-Up Aux Charge shall be calculated by applying the applicable “energy charge” rates to the Start-Up Aux Energy amount proportional to amount of time elapsed under each applicable “peak” period. Start-Up Charge: The applicable charge ($) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Fuel: The applicable volume of natural gas (MMBtu) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Notice: As set forth in Section 9.2(b) of this Confirmation. Start-Up Time: The applicable amount of time (minutes) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Station Use: The electrical load of the Generating Unit’s auxiliary equipment. The auxiliary equipment includes forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems, control systems, and sump pumps. Substitution Cost: As set forth in Section 6.5 of this Confirmation. Substitution Rules: As set forth in Section 6.5 of this Confirmation. Successful Repair: Immediately upon completion of the repairs to a Generating Unit, Seller demonstrates, at Seller’s expense, to SCE’s reasonable satisfaction, that such Generating Unit can: (i) Start-Up and ramp up to and remain at full load for two (2) consecutive hours, and (ii) immediately thereafter remain available to generate Energy under this Confirmation by a quantity greater than or equal to ninety-eight percent (98%) of Contract Capacity for seven (7) consecutive days. Supply Plan: As set forth in the Tariff. Tariff: The tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. Term: As set forth in Section 1.3 of this Confirmation. Test Parameters: Shall have the meaning specified in Appendix 10.2 Trading Day: The day in which Day Ahead trading occurs in accordance with the WECC Preschedule

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Calendar. Transfer Date 1: The first (1st) Business Day of the month in which the Auction immediately following the end of the Delivery Period is to take place. Transfer Date 2: The first (1st) Business Day of the month in which the Auction immediately following the end of each year during the Delivery Period that Seller must satisfy its annual compliance obligation (as described in Section 95855 of the GHG Regulations) is to take place. Transfer Date 3: The first (1st) Business Day of the month in which the Auction immediately following the end of the applicable Compliance Period is to take place, if such Compliance Period ends during the Delivery Period. Transfer Notice: As set forth in Section 20.4(b)(v). Transmission Owner: As set forth in the Tariff. Transition PPA: As set forth in the Transition Cover Sheet. Transition RA Confirmation: That certain Resource Adequacy Confirmation dated herewith between Seller and SCE, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. Turbine Configuration: As set forth in Appendix 1.8 of this Confirmation. UDP: Uninstructed Deviation Penalty, as applied to each SC by the CAISO, or any successor thereto pursuant to the Tariff. Uninstructed Deviation GMC Rate: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term to UIE. Upper MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Variable O&M Charge: As set forth in Appendix 3.1(b) of this Confirmation. Variable O&M Payment: As set forth in Section 3.1(b) of this Confirmation. WECC Preschedule Calendar: The Preschedule Calendar(s) as set forth or described on the WECC website at http://www.wecc.biz.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 1.4 CONTRACT CAPACITY, ANCILLARY SERVICES AND OPERATING RESTRICTIONS Technology:

COMBUSTION TURBINE Kern River Cogeneration Company Unit 1

Generating Unit Name: A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information

Minimum Load, PMin (MW):

70.00

PMax (MW):

78.00

Max capacity w/o duct burners (MW):

78.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

78.00

1.00

Maximum Daily Run Hours

Best Operational Minimum Down Ramp Rate Time (minutes): (MW/min) 60.00

3.00

No

Minimum Run Time (minutes):

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Ancillary Services are included: Yes Black Start included: Yes KRCC is not currently included in Black Start Capability Plan Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Technology:

COMBUSTION TURBINE Kern River Cogeneration Company Unit 3

Generating Unit Name: A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information

Minimum Load, PMin (MW):

70.00

PMax (MW):

80.00

Max capacity w/o duct burners (MW):

80.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Daily Run Hours

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

80.00

1.00

Best Operational Minimum Down Ramp Rate Time (minutes): (MW/min) 60.00

3.00

No

Minimum Run Time (minutes):

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Yes Ancillary Services are included: Yes KRCC is not currently included in Black Start Capability Plan Black Start included: Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

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A/S Minimum Capacity(MW)

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 1.6 ENERGY DELIVERY POINT

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 1.8 DESCRIPTION OF GENERATING UNITS AND DESCRIPTION OF SITE 1.

Generating Units Description.

a.

Generating Unit # 1 i.

Name: Kern River Cogeneration Company Unit # 1

ii.

Location: SW China Grade Loop, Bakersfield, California

iii.

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 1

iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: 77.25 MW. v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

b.

xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 77.25

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 101514

Generating Unit # 3 i.

Name: Kern River Cogeneration Company Unit # 3

ii.

Location: SW China Grade Loop, Bakersfield, California

iii.

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 3

iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: 77.25 MW v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 77.25

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 101514

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

2.

Site Description. Kern River Cogeneration Company Plant Site

THAT PORTION OF SECTION 32, TOWNSHIP 28 SOUTH, RANGE 25 EAST, H.D.M., IN THE COUNTY OF KERN. STATE OF CALIFORNIA. DESCRIBED AS FOLLOWS: COMMENCING AT THE NORTHWEST CORNER OF SAID SECTION 32; THENCE SOUTH 00 DEGREES 22 MINUTES 14 SECONDS WEST ALONG THE WEST LINE OF THE NORTHWEST QUARTER OF SAID SECTION 32, A DISTANCE OF 1271.73 FEET; THENCE DEPARTING SAID WEST LINE SOUTH 85 DEGREES 37 MINUTES 46 SECONDS EAST A DISTANCE OF 2219.62 FEET TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION; THENCE (1) N.86 DEG. 36 MIN. 19 SEC E., A DISTANCE OF 88.81 FEET; THENCE (2) N.78 DEG. 25 MIN. 31 SEC E., A DISTANCE OF 36.40 FEET; THENCE (3) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 45.00 FEET; THENCE (4) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 40.00 FEET; THENCE (5) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 120.00 FEET; THENCE (6) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (7) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 13.00 FEET; THENCE (8) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (9) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 8.00 FEET; THENCE (10) N.10 DEG. 44 MIN. 52 SEC E., A DISTANCE OF 171.06 FEET; THENCE (11) N.18 DEG. 37 MIN. 55 SEC W., A DISTANCE OF 230.31 FEET; THENCE (12) N.13 DEG. 49 MIN. 58 SEC E., A DISTANCE OF 48.66 FEET; THENCE (13) N.41 DEG. 14 MIN. 26 SEC E., A DISTANCE OF 50.00 FEET; THENCE (14) N.56 DEG. 04 MIN. 49 SEC E., A DISTANCE OF 48.41 FEET; THENCE (15) N.77 DEG. 21 MIN. 00 SEC E., A DISTANCE OF 51.24 FEET; THENCE (16) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 43.00 FEET; THENCE (17) S.60 DEG. 42 MIN. 03 SEC E., A DISTANCE OF 156.59 FEET; THENCE (18) N.87 DEG. 20 MIN. 32 SEC E., A DISTANCE OF 73.55 FEET; THENCE (19) S.56 DEG. 34 MIN. 29 SEC E., A DISTANCE OF 30.89 FEET; THENCE (20) S.20 DEG. 32 MIN. 03 SEC E., A DISTANCE OF 30.87 FEET; THENCE (21) S.06 DEG. 54 MIN. 55 SEC W., A DISTANCE OF 225.22 FEET; THENCE (22) S.04 DEG. 22 MIN. 14 SEC W., A DISTANCE OF 90.00 FEET; THENCE (23) S.03 DEG. 11 MIN. 03 SEC W., A DISTANCE OF 95.34 FEET; THENCE (24) S.01 DEG. 19 MIN. 04 SEC W., A DISTANCE OF 75.11 FEET; THENCE (25) S.17 DEG. 07 MIN. 51 SEC E., A DISTANCE OF 35.47 FEET; THENCE (26) S.19 DEG. 37 MIN. 32 SEC W., A DISTANCE OF 34.21 FEET; THENCE (27) S.12

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

DEG. 52 MIN. 15 SEC E., A DISTANCE OF 30.36 FEET; THENCE (28) S.82 DEG. 43 MIN. 07 SEC E., A DISTANCE OF 59.08 FEET; THENCE (29) S.66 DEG. 18 MIN. 47 SEC E., A DISTANCE OF 102.79 FEET; THENCE (30) N.89 DEG. 14 MIN. 33 SEC E., A DISTANCE OF 78.31 FEET; THENCE (31) N.53 DEG. 27 MIN. 22 SEC E., A DISTANCE OF 19.85 FEET; THENCE (32) N.18 DEG. 54 MIN. 18 SEC E., A DISTANCE OF 27.89 FEET; THENCE (33) N.76 DEG. 33 MIN. 06 SEC E., A DISTANCE OF 29.41 FEET; THENCE (34) N.60 DEG. 40 MIN. 50 SEC E., A DISTANCE OF 14.42 FEET; THENCE (35) N.24 DEG. 01 MIN. 28 SEC E., A DISTANCE OF 29.73 FEET; THENCE (36) S.74 DEG. 54 MIN. 59 SEC E., A DISTANCE OF 37.66 FEET; THENCE (37) N.80 DEG. 20 MIN. 04 SEC E., A DISTANCE OF 49.48 FEET; THENCE (38) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 20.00 FEET; THENCE (39) S.55 DEG. 03 MIN. 01 SEC E., A DISTANCE OF 25.55 FEET; THENCE (40) S.30 DEG. 37 MIN. 17 SEC E., A DISTANCE OF 24.41 FEET; THENCE (41) S.03 DEG. 13 MIN. 27 SEC E., A DISTANCE OF 30.27 FEET; THENCE (42) S.16 DEG. 11 MIN. 08 SEC E., A DISTANCE OF 42.27 FEET; THENCE (43) S.37 DEG. 28 MIN. 55 SEC W., A DISTANCE OF 109.84 FEET; THENCE (44) S.00 DEG. 13 MIN. 33 SEC W., A DISTANCE OF 207.54 FEET; THENCE (45) S.61 DEG. 20 MIN. 48 SEC W., A DISTANCE OF 23.85 FEET; THENCE (46) N.79 DEG. 55 MIN. 08 SEC W., A DISTANCE OF 20.10 FEET; THENCE (47) N.50 DEG. 43 MIN. 37 SEC W., A DISTANCE OF 52.43 FEET; THENCE (48) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 80.00 FEET; THENCE (49) S.47 DEG. 58 MIN. 24 SEC W., A DISTANCE OF 58.00 FEET; THENCE (50) S.00 DEG. 38 MIN. 21 SEC W., A DISTANCE OF 46.10 FEET; THENCE (51) S.25 DEG. 29 MIN. 43 SEC W., A DISTANCE OF 47.17 FEET; THENCE (52) S.74 DEG. 02 MIN. 51 SEC W., A DISTANCE OF 57.58 FEET; THENCE (53) S.71 DEG. 32 MIN. 13 SEC W., A DISTANCE OF 20.62 FEET; THENCE (54) N.84 DEG. 29 MIN. 01 SEC W., A DISTANCE OF 50.01 FEET; THENCE (55) S.87 DEG. 51 MIN. 03 SEC W., A DISTANCE OF 70.46 FEET; THENCE (56) S.78 DEG. 15 MIN. 26 SEC W., A DISTANCE OF 46.84 FEET; THENCE (57) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 40.36 FEET; THENCE (58) S.74 DEG. 57 MIN. 33 SEC W., A DISTANCE OF 111.33 FEET; THENCE (59) N.63 DEG. 11 MIN. 37 SEC W., A DISTANCE OF 167.69 FEET; THENCE (60) N.45 DEG. 49 MIN. 26 SEC W., A DISTANCE OF 39.05 FEET; THENCE (61) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 26.91 FEET; THENCE (62) N.04 DEG. 59 MIN. 23 SEC W., A DISTANCE OF 92.23 FEET; THENCE (63) N.07 DEG. 43 MIN. 27

52

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

SEC W., A DISTANCE OF 71.59 FEET; THENCE (64) N.19 DEG. 15 MIN. 01 SEC E., A DISTANCE OF 214.18 FEET; THENCE (65) N.07 DEG. 53 MIN. 39 SEC W., A DISTANCE OF 23.54 FEET; THENCE (66) N.35 DEG. 26 MIN. 06 SEC W., A DISTANCE OF 31.24 FEET; THENCE (67) N.63 DEG. 49 MIN. 41 SEC W., A DISTANCE OF 16.16 FEET; THENCE (68) N.81 DEG. 48 MIN. 55 SEC W., A DISTANCE OF 75.17 FEET; THENCE (69) S.86 DEG. 24 MIN. 03 SEC W., A DISTANCE OF 50.49 FEET; THENCE (70) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 34.00 FEET; TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION.

53

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 3.1(a) DELIVERY PERIOD AND MONTHLY CAPACITY PAYMENT

54

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015 $3.15 $3.15 $3.15 $3.15

Monthly Capacity Price[1] ($/kW-month)

[1] Monthly Capacity Price expressed in whole dollars and cents B. Monthly Payment Price Shape Table [2] Month 2012 2013 2014 2015 2016 January 0% 20% 20% 96% 0% February 0% 10% 10% 48% 0% March 0% 10% 10% 48% 0% April 0% 10% 10% 48% 0% May 0% 30% 30% 144% 0% June 0% 45% 45% 216% 0% July 0% 330% 330% 0% 0% August 0% 405% 405% 0% 0% September 0% 240% 240% 0% 0% October 105% 35% 35% 0% 0% November 75% 25% 25% 0% 0% December 120% 40% 40% 0% 0% [2] Price shape is determined based on the heat rate of the Generating Unit, these values are contained in the All Source RFO Instructions. C. Maximum Monthly Capacity Payment ($) Month 2012 2013 2014 2015 2016 January $ - $ 46,620.00 $ 46,620.00 $ 223,776.00 $ - $ February $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ March $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ April $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ May $ - $ 69,930.00 $ 69,930.00 $ 335,664.00 $ - $ June $ - $ 104,895.00 $ 104,895.00 $ 503,496.00 $ - $ July $ - $ 769,230.00 $ 769,230.00 $ - $ - $ August $ - $ 944,055.00 $ 944,055.00 $ - $ - $ September $ - $ 559,440.00 $ 559,440.00 $ - $ - $ October $ 244,755.00 $ 81,585.00 $ 81,585.00 $ - $ - $ November $ 174,825.00 $ 58,275.00 $ 58,275.00 $ - $ - $ December $ 279,720.00 $ 93,240.00 $ 93,240.00 $ - $ - $

Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

55

2018 $ $ $ $ $ $ $ $ $ $ $ $

2017 -

2018 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2017 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

12.200

2019

2019 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Enter Heat Rate at Pmax (MMBTU/MWh)

For the purposes of this template, figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year.

A. Monthly Capacity Price Information

Generating Unit Name: Kern River Cogeneration Company Unit 1

-

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

$ $ $ $ $ $ $ $ $ $ $ $

2020

2020 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 2013 2014 2015

Calendar Year

-

$ $ $ $ $ $ $ $ $ $ $ $

2021

2021 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

74.00

Contract Capacity (MW)

-

$ $ $ $ $ $ $ $ $ $ $ $

2022

2022 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

2023

2023 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

Base Price Shape 20% 10% 10% 10% 30% 45% 330% 405% 240% 35% 25% 40%

2024

2024 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015 $3.15 $3.15 $3.15 $3.15

Monthly Capacity Price[1] ($/kW-month)

[1] Monthly Capacity Price expressed in whole dollars and cents B. Monthly Payment Price Shape Table [2] Month 2012 2013 2014 2015 2016 January 0% 20% 20% 96% 0% February 0% 10% 10% 48% 0% March 0% 10% 10% 48% 0% April 0% 10% 10% 48% 0% May 0% 30% 30% 144% 0% June 0% 45% 45% 216% 0% July 0% 330% 330% 0% 0% August 0% 405% 405% 0% 0% September 0% 240% 240% 0% 0% October 105% 35% 35% 0% 0% November 75% 25% 25% 0% 0% December 120% 40% 40% 0% 0% [2] Price shape is determined based on the heat rate of the Generating Unit, these values are contained in the All Source RFO Instructions. C. Maximum Monthly Capacity Payment ($) Month 2012 2013 2014 2015 2016 January $ - $ 46,620.00 $ 46,620.00 $ 223,776.00 $ - $ February $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ March $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ April $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ May $ - $ 69,930.00 $ 69,930.00 $ 335,664.00 $ - $ June $ - $ 104,895.00 $ 104,895.00 $ 503,496.00 $ - $ July $ - $ 769,230.00 $ 769,230.00 $ - $ - $ August $ - $ 944,055.00 $ 944,055.00 $ - $ - $ September $ - $ 559,440.00 $ 559,440.00 $ - $ - $ October $ 244,755.00 $ 81,585.00 $ 81,585.00 $ - $ - $ November $ 174,825.00 $ 58,275.00 $ 58,275.00 $ - $ - $ December $ 279,720.00 $ 93,240.00 $ 93,240.00 $ - $ - $

Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

56

2018 $ $ $ $ $ $ $ $ $ $ $ $

2017 -

2018 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2017 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

12.200

2019

2019 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Enter Heat Rate at Pmax (MMBTU/MWh)

For the purposes of this template, figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year.

A. Monthly Capacity Price Information

Generating Unit Name: Kern River Cogeneration Company Unit 3

-

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

$ $ $ $ $ $ $ $ $ $ $ $

2020

2020 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 2013 2014 2015

Calendar Year

-

$ $ $ $ $ $ $ $ $ $ $ $

2021

2021 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

74.00

Contract Capacity (MW)

-

$ $ $ $ $ $ $ $ $ $ $ $

2022

2022 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

2023

2023 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

Base Price Shape 20% 10% 10% 10% 30% 45% 330% 405% 240% 35% 25% 40%

2024

2024 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 3.1(b)

VARIABLE O&M CHARGE Generating Unit Name:

Kern River Cogeneration Company Unit 1

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Generating Unit Name:

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

Kern River Cogeneration Company Unit 3

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

57

Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 3.1(c) START-UP CHARGE AND CAPACITY AND ANCILLARY SERVICES OPERATING RESTRICTIONS Generating Unit Name:

Kern River Cogeneration Company Unit 1

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

0.00

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

58

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Generating Unit Name:

Kern River Cogeneration Company Unit 3

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

0.00

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

59

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 5.3 HEAT RATE A. Configuration 1 Information Minimum Generation Capacity (MW):

Maximum Generation Capacity (MW):

70.00

Heat Rate @ Pmax

78.00

12.200

Heat Rate @ Pmin

12.500

Increment (MW):

B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.500

0.00

0.00

0.00

0.00

71.00

12.440

0.00

0.00

0.00

0.00

72.00

12.380

0.00

0.00

0.00

0.00

73.00

12.320

0.00

0.00

0.00

0.00

74.00

12.260

0.00

0.00

0.00

0.00

75.00

12.200

0.00

0.00

0.00

0.00

76.00

12.200

0.00

0.00

0.00

0.00

77.00

12.200

0.00

0.00

0.00

0.00

78.00

12.200

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

60

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Generating Unit Name:

Kern River Cogeneration Company Unit 3

A. Configuration 1 Information Minimum Generation Capacity (MW):

Maximum Generation Capacity (MW):

70.00

Heat Rate @ Pmax

80.00

12.200

Heat Rate @ Pmin

12.500

Increment (MW):

B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.500

0.00

0.00

0.00

0.00

71.00

12.440

0.00

0.00

0.00

0.00

72.00

12.380

0.00

0.00

0.00

0.00

73.00

12.320

0.00

0.00

0.00

0.00

74.00

12.260

0.00

0.00

0.00

0.00

75.00

12.200

0.00

0.00

0.00

0.00

76.00

12.200

0.00

0.00

0.00

0.00

77.00

12.200

0.00

0.00

0.00

0.00

78.00

12.200

0.00

0.00

0.00

0.00

79.00

12.200

0.00

0.00

0.00

0.00

80.00

12.200

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

61

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.1 AVAILABILITY NOTICE

Operating Day: Station:

Issued By:

Generating Unit:

Issued At:

Generating Unit 100% Available No Restrictions:

Hour Ending

Minimum Output (MW) (non AGC)

Available Capacity

AGC Available

AGC Min Limit

AGC Max Limit

(MW)

YES/NO

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

62

Comments

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.2(a) DISPATCH NOTICE

Operating Day: Station:

Issued By:

Generating Unit:

Hour Ending

Issued At:

Scheduled Energy

AGC Scheduled

Regulation Up

Regulation Down

Spinning Reserve

(MW)

YES/NO

(MW)

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

63

NonSpinning Reserves (MW)

Comments

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.2(b) START-UP NOTICE

Date: Station:

Issued By:

Generating Unit:

Issued At:

Date and Time Fire established in Applicable Generating Unit Date and Time Applicable Generating Unit Synchronized Date and Time Applicable Generating Unit Released for Dispatch Type of Start-Up (Hot, Warm, Cold) Fuel Consumed During Start-Up

(MMBtu)

64

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.2(d) DAILY OPERATING REPORT Daily Operating Reports submitted under this Confirmation should be provided in Excel. For: MM/DD/YY Plant Status at 0600

Generating Unit Name

Replicate for each Generating Unit

Current Availability (MW) Current Operating Level (MW) Current Restrictions (MW)

Prior Day Operating Level (HE)

Hourly Operating Level (Integrated)

Hourly Availability (Integrated)

Generating Unit on AS Control (Y/N)

Nature of Outage

Course of Action to Repair

Outage Date / Return Date

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00 Total Prior Day Significant Events:

Outages (Name of Equipment)

65

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.2(e) COMMUNICATION PROTOCOLS Communication Protocols These Communication Protocols are subject to change and shall be modified as evolving market conditions and rules may require. 1. Contacts and Authorized Representatives The “Contact Information” tables set forth those contact functions, phone/fax numbers and e-mail information by which each Party elects to be contacted by the other. Notification provided under this Confirmation shall be made to the applicable point of contact as set forth in the Contact Information Table. A Party may update its Contact Information by providing notice to the other Party. 2. Communication Protocols: General 2.1 Intra-day Communication: All communications and notices between the Parties that occur intra-day and intra-hour for the applicable Operating Day including those regarding emergencies, Dispatch Notices, Availability Notices, and notices to avoid imbalance penalties, uninstructed deviation charges/credits or any other CAISO charges shall be provided electronically or telephonically as SCE directs to the applicable Party. If to Seller, such notices and communications shall be provided to the following contact, in order of priority, (1) Dispatch Desk/Control Room, (2) Plant Manager, (3) Executive Director. If to SCE, such notices and communications shall be provided to the following contact, in order of priority, Real Time and Natural Gas Scheduling. Each Party shall confirm all Intra-day Communication either electronically or via telephone as soon as practicable. 2.2 Communication Failure: In the event of a failure of the primary communication link between Seller and SCE, both Parties will try all available means to communicate, including cell phones or additional communication devices as installed. 2.3 System Emergency: SCE and Seller shall communicate as soon as possible all changes to the schedule requested by the CAISO as a result of a system emergency. 2.4 Confidentiality: Confidential communications between the Parties in discharging their rights and obligations under the Confirmation and these Communication Protocols will be subject to the applicable restrictions set forth in the Confirmation. 2.5 Staffing: The Parties will have available twenty-four (24) hours a day, seven (7) days a week, personnel available to communicate regarding the implementation of these Communication Protocols.

66

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Contact Information Table Contacts and Authorized Representatives for SCE Outlined below is the contact and communication information for the relevant contact groups. This list may be amended by SCE with timely notice to Seller. Primary Phone

Contact

Secondary Phone

Day-Ahead Trading

626-307-4487

Day-Ahead Scheduling

626-307-4425

Gas Trading Gas Scheduling

Fax

Email

626-302-3409

[email protected]

626-307-4420

626-302-3409

[email protected]

626-307-4480

626-302-4410*

626-302-3410

[email protected]

626-307-4479

626-302-4410*

626-302-3410

[email protected]

626-307-4410

Cell: 818-424-4575 Sat. Phone: 877-2482129 GOC Fly Away: 877220-9509 (only active in emergencies)

626-302-3409

[email protected] [email protected]

626-307-4410

Cell: 949-466-9909 Sat. Phone: 877-8065625

949-206-7840

[email protected] [email protected]

626-302-3277

626-302-3378

626-302-3276

[email protected]

Contract Administration

626-302-3216

[insert CM phone here]

626-302-8168

ESMpowercontractadmin@sce .com

Outage Scheduling / RA Substitution

626-302-3400

[email protected]

Availability Notices

626-302-3400

[email protected]

Real Time Notifications

Real Time – Backup Operations Center (not staffed, emergency only) Settlements – Power & Gas

*Contact the Real Time Generation Desk if after hours; RT will contact the on-call Gas Trader/Scheduler

Contacts and Authorized Representatives for Seller Outlined below is the contact and communication information for the relevant Seller employees. This list may be amended by Seller with timely notice to SCE. Desk

Contact

Direct Phone

Secondary Phones

Dispatch Desk (Day-Ahead) Dispatch Desk (Real Time) Outage Desk Plant Manager

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Fax

Email

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Contract Administration Settlements Operations Manager Operations Supervisor

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APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the relevant provisions of PTC 22. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). Site Specific Reference Conditions (provided by Seller) Inlet Air (“Inlet Air”) Temperature (in °F)

38

Inlet Air Relative Humidity (in %)

25

Barometric Pressure (inches Hg)

28.5

For each Test set forth in this Appendix, the measured test data will be corrected to the Site Specific Reference Conditions using established correction factors. The corrected test data will then be compared to the Test Parameters. B. Parameters. During any Test, at a minimum, the following parameters will be measured and recorded simultaneously for the Generating Unit at no greater than fifteen (15) minute intervals (except for fuel samples): 1) 2) 3) 4) 5) 6) 7) 8)

instantaneous Inlet Air relative humidity (%) with instruments installed in the inlet filter house; instantaneous ambient barometric pressure (inches Hg) with transmitters located near the horizontal centerline of the Generating Unit; instantaneous Inlet Air temperature (°F) with four (4) remote telemetry devices installed in an array inside the filter house; instantaneous site ambient temperature (°F); fuel flow at the Generating Unit natural gas meter (SCFH); net plant output as measured at the Energy Delivery Point (MW); heat rate (BTU/kWh) @ PMax (for testing purposes only) continuous emissions monitoring system (CEMS) data required per air permit.

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Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a qualified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters which will be defined in the Final Test Plan (Part III, A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time prior to commencing the four (4) hour test; operated for at least four (4) hours at an output, when corrected to Site Specific Reference conditions, is equal to PMax (“Full Load”); and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1. SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized and brought to Full Load using normal start procedures and then operated continuously at Full Load for as long as it is necessary, but in no case for no less than one (1) hour, for all measured parameters to achieve stable, normal conditions. During any 30minute period of any Test, all measured parameters will not exceed the values provided in Table 3-3.5 of PTC 22, “Maximum Permissible Standard Deviations of Measurements in Operating Conditions” in addition to the following: Variable Natural Gas Heating Value (Unit Volume) Absolute Inlet Air Pressure (inches H20)

Permissible Deviation ± 1.3% ± 0.33%

E. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in Part III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the equipment manufacturer for operation at PMax. F. Test Conditions. At all times during a Full Load Test, the Generating Unit shall be operated with any inlet cooling treatment systems on and such unit shall not be subject to abnormal operating conditions such as (i) ambient conditions requiring the inlet cooling system to be turned off in accordance with manufacturer’s specifications; (ii) unstable load conditions; (iii) equipment, operating or regulatory restrictions or (iv) changes in the Generating Unit’s electrical output other than those fluctuations naturally arising from variations in ambient temperature. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with Part II.J. below.

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G. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. H. Air Emissions. Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) Rule 2000 (c)(18) CEMS, is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. I. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Site Ambient Air Temperature Inlet Air Temperature Inlet Air Relative Humidity Barometric Pressure Measured Net Power Output Inlet Air Treatment (Evaporative Cooler, Foggers, or Chiller) Power Factor Steam / Water Injection Generating Unit Emissions Fuel Heating Value (HHV)

°F (Dry Bulb) °F (Dry Bulb) % inches Hg MW on/off

on/off (if applicable) Actual and permit levels BTU/Cubic ft

Note: If fuel analysis is not available by the fourth day after the Test is completed, Seller shall provide it on the earlier of when available or ten (10) Business Days after the Test is completed. J. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with Part II.I. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf,

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SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives, at Seller’s expense. K. Final Report. Within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 22. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8) (9)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3-5 of PTC 22; demonstration of the correction of the measured test data to the Site Specific Reference Conditions, with supporting calculations; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. L. Operating Personnel. During any Test, the same operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. M. SCE Representative. SCE shall be entitled to have at least two representatives present to witness each Test.

PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in Part II, above and in accordance with applicable Subsections of PTC 22, Section 3. At least ten (10) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and the temporary instrumentation suggested by Seller or deemed necessary by SCE in its sole judgement. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with written notice of the temporary calibrated instrumentation that will be used during the Test. Seller shall calibrate or cause to be calibrated all such instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All

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electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE prior to the Test. Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. In addition Seller shall provide a temporary data acquisition system to monitor all temporary instruments. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling each Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1(a) of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test. G. Table. If SCE requests, Seller shall create a table relating Contract Capacity (in MW) to Inlet Air temperature, such that the Contract Capacity of the Generating Unit shall be the expected output of the Generating Unit at Test Conditions, and the expected output of the Generating Unit at other Inlet Air temperatures shall relate to Contract Capacity in the same proportion as the points on the manufacturer’s performance curve relate to that curve at Test Conditions. Such table will be provided to SCE as part of the Final Report.

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APPENDIX 11.1 PLANNED OUTAGE REPORT

Planned Outage Reports submitted under this Confirmation should be provided in Excel.

DATE OF UPDATE RESOURCE NAME Replicate for each Generating Unit

Planned Outages Start Date

HE

End Date

74

HE

MW Available

Cause

Emergency Time of Return

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 12.3 DELIVERY OF DATA The following is a list of real time generic data points to be electronically exchanged between Seller and SCE. SCE may add items to or delete items from this list at its reasonable discretion prior to the beginning of the Delivery Period. Additional meetings will be scheduled to clarify and finalize points list prior to configuration tasks.

Point description: From Generator DNP - XXX UNIT# Breaker DNP - XXX UNIT# AGC CTRL AVAILABILITY ONOFF DNP - XXX UNIT# ISO RIG Lost Communication DNP - XXX UNIT# High Operating Limit DNP - XXX UNIT# Low Operating Limit DNP - XXX UNIT# ISO AGC set point DNP - XXX UNIT# Net MW (POD) DNP - XXX UNIT# Capacity DNP - XXX UNIT# Max Sustained Ramp Rate

From GMS Control Related DNP - XXX UNIT# AGC model - ISO AGC DNP - XXX UNIT# AGC model – SFM DNP - XXX UNIT# AGC model – MAN DNP - XXX UNIT# AGC model – OFF DNP - XXX UNIT# Dispatch Energy Schedule "GO TO" DNP - XXX UNIT# Reg Up Awarded MW DNP - XXX UNIT# Reg Down Awarded MW DNP - XXX UNIT# Spin Awarded MW DNP - XXX UNIT# Non-Spin Awarded MW DNP - XXX UNIT# Set Point (MW) DNP - XXX UNIT# Ramp Rate (MW/M)

From GMS Schedules Related DNP - SCH HA Today XXX UNIT# HE01 DNP - SCH HA Today XXX UNIT# HE02 DNP - SCH HA Today XXX UNIT# HE03 DNP - SCH HA Today XXX UNIT# HE04 DNP - SCH HA Today XXX UNIT# HE05 DNP - SCH HA Today XXX UNIT# HE06 DNP - SCH HA Today XXX UNIT# HE07 DNP - SCH HA Today XXX UNIT# HE08 DNP - SCH HA Today XXX UNIT# HE09 DNP - SCH HA Today XXX UNIT# HE10 DNP - SCH HA Today XXX UNIT# HE11 DNP - SCH HA Today XXX UNIT# HE12 DNP - SCH HA Today XXX UNIT# HE13

75

From GMS Schedules Related (cont.) DNP - SCH HA Today XXX UNIT# HE14 DNP - SCH HA Today XXX UNIT# HE15 DNP - SCH HA Today XXX UNIT# HE16 DNP - SCH HA Today XXX UNIT# HE17 DNP - SCH HA Today XXX UNIT# HE18 DNP - SCH HA Today XXX UNIT# HE19 DNP - SCH HA Today XXX UNIT# HE20 DNP - SCH HA Today XXX UNIT# HE21 DNP - SCH HA Today XXX UNIT# HE22 DNP - SCH HA Today XXX UNIT# HE23 DNP - SCH HA Today XXX UNIT# HE24 DNP - SCH HA Today XXX UNIT# HE25 DNP - SCH HA Tomorrow XXX UNIT# HE01 DNP - SCH HA Tomorrow XXX UNIT# HE02 DNP - SCH HA Tomorrow XXX UNIT# HE03 DNP - SCH HA Tomorrow XXX UNIT# HE04 DNP - SCH HA Tomorrow XXX UNIT# HE05 DNP - SCH HA Tomorrow XXX UNIT# HE06 DNP - SCH HA Tomorrow XXX UNIT# HE07 DNP - SCH HA Tomorrow XXX UNIT# HE08 DNP - SCH HA Tomorrow XXX UNIT# HE09 DNP - SCH HA Tomorrow XXX UNIT# HE10 DNP - SCH HA Tomorrow XXX UNIT# HE11 DNP - SCH HA Tomorrow XXX UNIT# HE12 DNP - SCH HA Tomorrow XXX UNIT# HE13 DNP - SCH HA Tomorrow XXX UNIT# HE14 DNP - SCH HA Tomorrow XXX UNIT# HE15 DNP - SCH HA Tomorrow XXX UNIT# HE16 DNP - SCH HA Tomorrow XXX UNIT# HE17 DNP - SCH HA Tomorrow XXX UNIT# HE18 DNP - SCH HA Tomorrow XXX UNIT# HE19 DNP - SCH HA Tomorrow XXX UNIT# HE20 DNP - SCH HA Tomorrow XXX UNIT# HE21 DNP - SCH HA Tomorrow XXX UNIT# HE22 DNP - SCH HA Tomorrow XXX UNIT# HE23 DNP - SCH HA Tomorrow XXX UNIT# HE24 DNP - SCH HA Tomorrow XXX UNIT# HE25

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 13.3(c) DISCLOSURE SCHEDULE None

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APPENDIX 13.3(d)

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HISTORICAL OUTAGE REPORT KERN RIVER COGENERATION COMPANY GENERATING UNIT #1 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

Available Time Thu 01Jan09 00:00 Sat 03Jan09 15:09 Sun 04Jan09 06:20 Sat 14Feb09 13:54 Tue 10Mar09 17:37 Sat 04Apr09 08:00 Sat 09May09 20:00 Sat 10Oct09 13:58 Tue 13Oct09 21:31 Fri 16Oct09 02:02 Fri 16Oct09 22:26 Sat 21Nov09 13:58 Sat 16Jan10 15:01 Mon 08Mar10 07:54 Sat 24Apr10 08:41 Mon 01Nov10 11:41 Mon 01Nov10 21:26 Tue 02Nov10 12:21 Mon 08Nov10 07:00 Thu 11Nov10 10:44 Sat 01Jan11 14:21 Wed 02Feb11 10:27 Wed 09Mar11 12:51 Mon 07Nov11 07:48 Mon 07Nov11 08:10 Mon 07Nov11 09:10 Sat 03Dec11 11:32 Sun 04Dec11 02:52 Sun 04Dec11 09:17 Mon 05Dec11 07:46 Tue 06Dec11 08:45 Wed 07Dec11 09:57 Thu 08Dec11 09:24 Thu 08Dec11 13:03 Fri 09Dec11 10:22 Thu 15Dec11 09:18 Tue 20Dec11 10:25 Fri 23Dec11 09:45 Sat 24Dec11 09:45 Sun 25Dec11 14:36 Mon 26Dec11 10:14 Tue 27Dec11 10:22 Wed 28Dec11 10:21 Thu 29Dec11 09:17 Fri 30Dec11 10:19 Sat 31Dec11 10:18 Sun 01Jan12 10:18 Mon 09Jan12 08:32 Fri 13Jan12 12:47 Tue 17Jan12 09:19 Thu 19Jan12 10:17 Sun 26Feb12 15:38

UnAvailable Time Available Hours Reason UnAvailable Sat 03Jan09 07:21 55.4 Crankwash Sat 03Jan09 16:50 1.7 Steam Line gasked replaced Sat 14Feb09 07:11 984.8 Crankwash Tue 10Mar09 15:59 578.1 Primary Reignition - Reset and Restarted Unit Sun 15Mar09 21:05 123.5 Generator Maintenance Sat 09May09 00:00 832.0 DCS Upgraded to Ovation Control System Fri 09Oct09 21:02 3673.0 Generator Field Voltage PTs and Transducers maintenance Tue 13Oct09 20:55 79.0 Trip on Loss of Excitation Fri 16Oct09 01:30 52.0 Trip on Loss of Excitation Fri 16Oct09 21:03 19.0 Replaced Inner Loop Regulator Card Sat 21Nov09 07:11 848.8 Crankwash Sat 16Jan10 07:12 1337.2 Crankwash Mon 08Mar10 00:13 1209.2 Crankwash Sun 18Apr10 21:09 997.2 Combustion Inspection - UnAvailable Mon 01Nov10 09:54 4585.2 Flashbacks induced Emissions Exceedence - Reset Mon 01Nov10 12:32 0.8 Flashbacks induced Emissions Exceedence - Washed Unit Mon 01Nov10 21:52 0.4 Unstable combustion system - failure to reignite primaries trip Tue 02Nov10 12:51 0.5 Unstable combustion system troubleshooting Mon 08Nov10 07:00 0.0 Combustion Inspection Sat 01Jan11 12:32 1225.8 Numerous Flashbacks - Reset and Restarted Wed 02Feb11 09:54 763.5 Flashbacks and High Emissions Wed 09Mar11 10:04 839.6 Cleaned dirty flame detectors - Pilot valve maintenance Mon 07Nov11 07:43 5826.9 Generator excitation system troubleshooting and adjustment Mon 07Nov11 07:48 0.0 Generator excitation system troubleshooting and adjustment Mon 07Nov11 08:10 0.0 Generator excitation system troubleshooting and adjustment Sat 03Dec11 08:02 622.9 Shutdown to avoid emissions exceedence Sun 04Dec11 00:05 12.5 Shutdown to avoid emissions exceedence Sun 04Dec11 03:52 1.0 Shutdown to avoid emissions exceedence Sun 04Dec11 21:46 12.5 Failed to reignite after flashback - cleaned flame detectors Tue 06Dec11 05:42 21.9 Shutdown to avoid emissions exceedence Tue 06Dec11 22:04 13.3 Shutdown to avoid emissions exceedence Thu 08Dec11 05:58 20.0 Shutdown to avoid emissions exceedence Thu 08Dec11 11:15 1.8 Shutdown to avoid emissions exceedence Thu 08Dec11 20:12 7.2 Shutdown to avoid emissions exceedence Thu 15Dec11 08:05 141.7 Shutdown to avoid emissions exceedence Tue 20Dec11 08:08 118.8 Shutdown to avoid emissions exceedence Fri 23Dec11 08:03 69.6 Shutdown to avoid emissions exceedence Sat 24Dec11 05:03 19.3 Shutdown to avoid emissions exceedence Sun 25Dec11 13:03 27.3 Shutdown to avoid emissions exceedence Mon 26Dec11 03:04 12.5 Shutdown to avoid emissions exceedence Tue 27Dec11 01:04 14.8 Shutdown to avoid emissions exceedence Tue 27Dec11 22:56 12.6 Shutdown to avoid emissions exceedence Thu 29Dec11 06:10 19.8 Shutdown to avoid emissions exceedence Fri 30Dec11 01:02 15.8 Shutdown to avoid emissions exceedence Sat 31Dec11 02:57 16.6 Shutdown to avoid emissions exceedence Sun 01Jan12 05:01 18.7 Unit Tripped - Flashback - Failed to Re-ignite Primaries Mon 09Jan12 03:54 185.6 Shutdown to avoid emissions exceedence Wed 11Jan12 00:08 39.6 Bleed Heat System Installed Tue 17Jan12 03:49 87.0 Shutdown to avoid emissions exceedence Thu 19Jan12 04:46 43.5 Shutdown to avoid emissions exceedence Sun 26Feb12 03:50 905.5 Voltz/Hertz Card Failure - Excitation System PT repair Tue 01May12 00:00 1544.4 End of Data Set Total Available Hours 28,040.0 Total Hours 29,184.0 % Available 96.08%

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KERN RIVER COGENERATION COMPANY GENERATING UNIT #3 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3

Available Time Thu 01Jan09 00:00 Sat 09May09 19:56 Tue 26May09 12:30 Fri 05Jun09 10:51 Sat 13Jun09 06:38 Sat 25Jul09 08:01 Sat 05Sep09 15:01 Tue 22Dec09 00:14 Sat 17Apr10 07:56 Mon 10May10 04:40 Tue 11May10 08:01 Mon 24May10 08:37 Wed 21Jul10 00:48 Sun 29Aug10 14:51 Tue 21Sep10 12:17 Thu 03Feb11 17:18 Thu 03Feb11 22:00 Fri 04Feb11 16:13 Tue 03May11 10:46 Mon 09May11 07:45 Tue 10May11 08:22 Sun 15May11 12:46 Mon 16May11 12:44 Thu 26May11 09:22 Sun 29May11 08:36 Mon 30May11 09:48 Tue 31May11 10:51 Wed 01Jun11 00:00 Sat 04Jun11 07:49 Mon 06Jun11 01:18 Mon 06Jun11 10:58 Thu 30Jun11 11:54 Tue 12Jul11 08:58 Wed 13Jul11 08:56 Thu 14Jul11 08:51 Fri 15Jul11 08:51 Sat 16Jul11 08:50 Sun 17Jul11 07:45 Mon 18Jul11 07:45 Tue 19Jul11 07:45 Thu 04Aug11 09:48 Tue 16Aug11 07:51 Wed 17Aug11 10:45 Sat 08Oct11 06:01 Mon 24Oct11 08:13 Mon 24Oct11 09:24 Wed 02Nov11 10:28 Wed 02Nov11 13:55 Fri 04Nov11 15:18 Fri 04Nov11 21:44 Sat 05Nov11 13:14 Sun 06Nov11 09:18 Mon 07Nov11 09:10 Tue 08Nov11 09:00 Wed 09Nov11 08:00 Thu 10Nov11 08:00 Fri 11Nov11 07:00 Sat 12Nov11 08:00 Sun 13Nov11 10:00 Mon 14Nov11 08:00 Tue 15Nov11 09:00

UnAvailable Time Sat 09May09 00:11 Tue 26May09 11:41 Fri 05Jun09 05:54 Sat 13Jun09 00:13 Sat 25Jul09 00:12 Sat 05Sep09 07:11 Mon 07Dec09 17:10 Mon 12Apr10 05:00 Mon 10May10 02:17 Tue 11May10 02:27 Sat 22May10 09:57 Tue 20Jul10 23:15 Sun 29Aug10 06:55 Tue 21Sep10 11:38 Thu 03Feb11 16:38 Thu 03Feb11 20:00 Thu 03Feb11 22:00 Tue 03May11 06:11 Sat 07May11 00:13 Tue 10May11 06:56 Sun 15May11 06:36 Sun 15May11 21:58 Mon 16May11 19:55 Thu 26May11 18:01 Mon 30May11 04:03 Tue 31May11 04:00 Tue 31May11 21:06 Wed 01Jun11 00:00 Sun 05Jun11 22:58 Mon 06Jun11 01:52 Wed 29Jun11 23:27 Tue 12Jul11 03:46 Wed 13Jul11 04:04 Thu 14Jul11 02:05 Fri 15Jul11 00:47 Sat 16Jul11 00:04 Sat 16Jul11 23:57 Mon 18Jul11 03:00 Tue 19Jul11 05:15 Thu 04Aug11 03:11 Sun 14Aug11 21:03 Tue 16Aug11 15:50 Sat 08Oct11 03:32 Fri 14Oct11 21:07 Mon 24Oct11 08:28 Wed 02Nov11 09:53 Wed 02Nov11 13:18 Fri 04Nov11 13:01 Fri 04Nov11 18:03 Fri 04Nov11 22:43 Sat 05Nov11 21:55 Sun 06Nov11 18:11 Mon 07Nov11 19:00 Tue 08Nov11 22:00 Thu 10Nov11 02:00 Fri 11Nov11 03:00 Sat 12Nov11 03:00 Sat 12Nov11 20:00 Sun 13Nov11 23:00 Mon 14Nov11 20:00 Wed 16Nov11 02:00

Available Hours 3072.2 399.8 233.4 181.4 1001.6 1007.2 2234.2 2668.8 546.3 21.8 265.9 1382.6 942.1 548.8 3244.4 2.7 0.0 2102.0 85.5 23.2 118.2 9.2 7.2 8.7 19.5 18.2 10.3 0.0 39.1 0.6 564.5 279.9 19.1 17.2 15.9 15.2 15.1 19.3 21.5 379.4 251.3 8.0 1240.8 159.1 0.2 216.5 2.8 47.1 2.8 1.0 8.7 8.9 9.8 13.0 18.0 19.0 20.0 12.0 13.0 12.0 17.0

79

Reason UnAvailable DCS Upgraded to Ovation Control System Emissions Exceedence - Cleaned Flame Detectors Emissions Exceedence - Flame Detectors Cleaned Crankwash CRANKWASH Crankwash - Gas Valve Inspection Emissions Exceedence - Combustion Inspection Combustion Inspection - UnAvailable Emissions Exceedence - Reset and Restarted Unit Emissions Exceedence - Cleaned Flame Detectors Emissions Exceedence - Mini CI - Replaced Primary Fuel Nozzles High NOx Emissions shutdown - Adjusted Nox Analyzer Crankwash Unit Tripped unintentionally while breaker testing Loss of Flame - Cleaned flame detectors High Nox and CO Cleaned Flame Detectors and changed Control Constants High NOx - Shutdown to avoid emissions exceedence Mini Combustion Inspection Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Mini CI - Replaced Primary and Secondary Fuel Nozzles Unable to Tune - Replaced Secondary Nozzles Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Mini CI - Replaced Fuel Nozzles and Liners Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Emissions Exceedence - Replaced #8 Secondary Fuel Nozzle Replaced Secondary Fuel Nozzles Emissions Exceedence - Replaced #3 Primary Fuel Nozzle Shutdown to avoid emissions exceedence Extended CI - Replaced 1st stage nozzle Shutdown to install missing secondary fuel nozzle port plug High combustion dynamics - Reset and restarted unit Unit tripped during recalibration of Humidity Transmitter Shut down unit to change combustion control constants Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Unit tripped on Failure to Reignite Primaries Shutdown to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Unit 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3

Available Time Wed 16Nov11 08:00 Thu 17Nov11 08:00 Fri 18Nov11 08:00 Sat 19Nov11 11:00 Sun 20Nov11 10:00 Mon 21Nov11 10:00 Tue 22Nov11 13:00 Wed 23Nov11 06:49 Fri 25Nov11 08:00 Sat 26Nov11 09:00 Sun 27Nov11 08:00 Mon 28Nov11 08:00 Tue 29Nov11 08:00 Wed 30Nov11 08:00 Thu 01Dec11 10:00 Fri 02Dec11 10:00 Sun 04Dec11 10:00 Mon 05Dec11 10:00 Tue 06Dec11 10:00 Wed 07Dec11 10:00 Thu 08Dec11 09:00 Fri 09Dec11 09:00 Sat 10Dec11 09:00 Sun 11Dec11 10:00 Mon 12Dec11 09:00 Tue 13Dec11 09:00 Wed 14Dec11 09:00 Thu 15Dec11 09:00 Fri 16Dec11 10:00 Sat 17Dec11 10:00 Sun 18Dec11 09:00 Mon 19Dec11 09:00 Tue 13Mar12 16:30 Wed 18Apr12 20:00

UnAvailable Time Available Hours Reason UnAvailable Wed 16Nov11 23:00 15.0 Unavailabe to avoid emissions exceedence Fri 18Nov11 01:00 17.0 Unavailabe to avoid emissions exceedence Fri 18Nov11 23:00 15.0 Unavailabe to avoid emissions exceedence Sat 19Nov11 18:00 7.0 Unavailabe to avoid emissions exceedence Sun 20Nov11 20:00 10.0 Unavailabe to avoid emissions exceedence Mon 21Nov11 21:00 11.0 Unavailabe to avoid emissions exceedence Tue 22Nov11 21:00 8.0 Unavailabe to avoid emissions exceedence Fri 25Nov11 00:00 41.2 Unavailabe to avoid emissions exceedence Fri 25Nov11 22:00 14.0 Unavailabe to avoid emissions exceedence Sat 26Nov11 22:00 13.0 Unavailabe to avoid emissions exceedence Sun 27Nov11 22:00 14.0 Unavailabe to avoid emissions exceedence Mon 28Nov11 21:00 13.0 Unavailabe to avoid emissions exceedence Tue 29Nov11 22:00 14.0 Unavailabe to avoid emissions exceedence Thu 01Dec11 00:00 16.0 Unavailabe to avoid emissions exceedence Thu 01Dec11 19:00 9.0 Unavailabe to avoid emissions exceedence Sat 03Dec11 19:00 33.0 Unavailabe to avoid emissions exceedence Sun 04Dec11 18:00 8.0 Unavailabe to avoid emissions exceedence Mon 05Dec11 18:00 8.0 Unavailabe to avoid emissions exceedence Tue 06Dec11 18:00 8.0 Unavailabe to avoid emissions exceedence Wed 07Dec11 19:00 9.0 Unavailabe to avoid emissions exceedence Thu 08Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Fri 09Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Sat 10Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Sun 11Dec11 20:00 10.0 Unavailabe to avoid emissions exceedence Mon 12Dec11 23:00 14.0 Unavailabe to avoid emissions exceedence Tue 13Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Wed 14Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Thu 15Dec11 20:00 11.0 Unavailabe to avoid emissions exceedence Fri 16Dec11 20:00 10.0 Unavailabe to avoid emissions exceedence Sat 17Dec11 19:00 9.0 Unavailabe to avoid emissions exceedence Sun 18Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Tue 13Mar12 00:00 2031.0 Replaced Fuel Gas Safties Tue 17Apr12 05:00 828.5 Transformer Maintenance PT and CT Inspection Tue 01May12 00:00 292.0 End of Data Set Total Available Hours 27,171.1 Total Hours 29,184.0 % Available 93.10%

80

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 14 SHAPED PRICE CALCULATION 1

Shape Calculation a) “Shape” shall be the ratio, expressed as a percentage, of a Forward Price Assessment of (i) the price of power for a calendar quarter to the price of power for the calendar year that such quarter falls within, or (ii) the price of power for a month to the price of power for the quarter that such month falls within. b) There are four quarterly Shapes (for the first through fourth calendar quarters) and twelve monthly Shapes (for the months of January through December) in every calendar year. 1.

For purposes of determining the applicable quarterly Shape, an annual price is calculated as the simple average of the four quarterly prices within the last available year. For example, the first quarter Shape is calculated using the formula below: ShapeQ1 = PQ1 / Average (PQ1 + PQ2 + PQ3 + PQ4)

2.

For purposes of determining the applicable monthly Shape, a quarterly price is calculated as the simple average of the three monthly prices within the applicable quarter. For example, the January Shape is calculated using the formula below: ShapeJan = PJan / Average (PJan + PFeb + PMar)

2

Calculation of Shaped Prices “Shaped Price” shall mean, if there is no Forward Price Assessment for the relevant calendar month, the price of power calculated in accordance with the following process. If no monthly price is available for a Forward Price Assessment but a quarterly price is available, then use a monthly Shape to calculate a monthly Shaped Price from a quarterly price using the following formula: PM = PQ × ShapeM Where: PM is the missing monthly power price PQ is the quarterly power price applicable to the relevant calendar month ShapeM is the applicable “Shape” for the missing month If no monthly or quarterly price is available for a Forward Price Assessment but an annual price is available, then use a quarterly Shape to calculate a quarterly Shaped Price from an annual price using the following formula: PQ = PY × ShapeQ Where: PQ is the missing quarterly power price PY is the yearly power price applicable to the applicable calendar quarter ShapeQ is the applicable “Shape” for the missing quarter

81

PARAGRAPH 10 to the COLLATERAL ANNEX to the EEI MASTER POWER PURCHASE AND SALE AGREEMENT Between Kern River Cogeneration Company (“Party A”) and Southern California Edison Company (“SCE” or “Party B”) CREDIT ELECTIONS COVER SHEET Paragraph 10. Elections and Variables I.

Collateral Threshold. A.

Party A Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party A shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party A; and provided further that, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party A Collateral Threshold” opposite the Credit Rating for [Party A][Party A’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party A][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing; provided, however, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand. Party A Collateral Threshold $__________ $__________ $__________ $__________ $__________



Credit Rating _______ (or above) _______ _______ _______ Below _______

The amount (“Threshold Amount”) which is the lowest of:

(1) the amount set forth below under the heading “Party A Collateral Threshold” opposite the lower of the Credit Ratings for Party A or, if applicable, Party A’s Guarantor on the relevant date of determination. If Party A or, if applicable, its Guarantor is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party A or, if applicable, its Guarantor is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party A or, if applicable,

1

its Guarantor does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) 80% of the amount of the guaranty agreement, as amended from time to time, provided by Party A’s Guarantor, if any, for the benefit of Party B; or (3) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing: Party A Collateral Threshold (in thousands of US Dollars) $25,000 $20,000 $20,000 $17,000 $9,000 $6,250 $3,750 $ 0 (zero)

B.

Moody’s Credit Rating

S&P Credit Rating

Fitch Credit Rating

Aa3 or above A1 A2 A3 Baa1 Baa2 Baa3 Ba1 or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party A’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Party B Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party B shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party B; and provided further that, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party B Collateral Threshold” opposite the Credit Rating for [Party B][Party B’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party B][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing; provided, however, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand:

2



Party B Collateral Threshold

_____Credit Rating

$__________ $__________ $__________ $__________ $__________

_______ (or above) _______ _______ _______ Below _______

The amount (the “Threshold Amount”) which is the lower of:

(1) the amount set forth below under the heading “Party B Collateral Threshold” opposite the lower of the Credit Ratings for Party B on the relevant date of determination. If Party B is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party B is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party B does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing: Party B Collateral Threshold (in thousands of US Dollars) $25,000 $20,000 $20,000 $17,000 $9,000 $6,250 $3,750 $ 0 (zero)

II.

Moody’s Credit Rating

S&P Credit Rating

Fitch Credit Rating

Aa3 or above A1 A2 A3 Baa1 Baa2 Baa3 Ba1 or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party B’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Eligible Collateral and Valuation Percentage. The following items will qualify as "Eligible Collateral" for the Party specified: Party A

Party B

Valuation Percentage

(A)

Cash

[X]

[X]

100%

(B)

Letters of Credit

[X]

[X]

100% unless either (i) a Letter of Credit Default shall have occurred and be continuing with respect to such Letter of Credit, or (ii) twenty (20) or fewer Business Days remain prior to the expiration of such Letter of Credit, in which cases the Valuation Percentage shall be zero (0%).

(C)

Other

[ ]

[ ]

3

________%

III.

Independent Amount. A.

B.

Party A Independent Amount. 

Party A shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount option is selected for Party A, then Party A (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party B (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party A’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex.



Party A shall have a Full Floating Independent Amount of (i) the amount specified in a Transaction or Confirmation, if any; and (ii) if Party A’s Credit Rating is lower than BBBby S&P, Baa3 by Moody’s, or BBB- by Fitch, the amount equal to ten percent (10%) of the market value of all outstanding Transactions (except those for which an alternative Independent Amount is specified in the Confirmation), adjusted by the netting of the market value of purchases with the market value of sales within the same billing cycles. If the Full Floating Independent Amount option is selected for Party A, then for purposes of calculating the Collateral Requirements pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party A shall be added to the Exposure Amount for Party B and subtracted from the Exposure Amount for Party A.



Party A shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party A, then Party A will be required to Transfer or cause to be Transferred to Party B Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party A otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced so long as Party A has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex.



Not Applicable.

Party B Independent Amount. 

Party B shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount Option is selected for Party B, then Party B (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party A (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party B’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex.

4

IV.

V.

VI.



Party B shall have a Full Floating Independent Amount of $______________. If the Full Floating Independent Amount Option is selected for Party B then for purposes of calculating Party B’s Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party B shall be added by Party A to its Exposure Amount for purposes of determining Net Exposure pursuant to Paragraph 3(a) of the Transition Collateral Annex.



Party B shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party B, then Party B will be required to Transfer or cause to be Transferred to Party A Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party B otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced for so long as Party B has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex.



Not Applicable.

Minimum Transfer Amount. A.

Party A Minimum Transfer Amount:

$0.00

B.

Party B Minimum Transfer Amount:

$0.00

Rounding Amount. A.

Party A Rounding Amount:

$250,000.00

B.

Party B Rounding Amount:

$250,000.00

Administration of Cash Collateral. A.

Party A Eligibility to Hold Cash. 

Party A shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B.



Party A shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party A or, if applicable, Party A’s Guarantor has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party A or its Guarantor has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or on “Credit Watch” negative or developing by

5

Fitch, then Party A shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party A is entitled to hold Cash, the Interest Rate payable to Party B on Cash shall be as selected below:

Party A Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

To the extent that Party A is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B. B.

Party B Eligibility to Hold Cash. 

Party B shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A.



Party B shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party B has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party B has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or “Credit Watch” negative or developing by Fitch, then Party B shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party B is entitled to hold Cash, the Interest Rate payable to Party A on Cash shall be as selected below: Party B Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

To the extent that Party B is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it

6

receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A. VII.

Notification Time. 10:00 a.m. Pacific Prevailing Time on a Local Business Day.

VIII.

General. With respect to the Collateral Threshold, Independent Amount, Minimum Transfer Amount and Rounding Amount, if no selection is made in this Cover Sheet with respect to a Party, then the applicable amount in each case for such Party shall be zero (0). In addition, with respect to the “Administration of Cash Collateral” section of this Paragraph 10, if no selection is made with respect to a Party, then such Party shall not be entitled to hold Performance Assurance in the form of Cash and such Cash, if any, shall be held in a Qualified Institution pursuant to Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. If a Party is eligible to hold Cash pursuant to a selection in this Paragraph 10 but no Interest Rate is selected, then the Interest Rate for such Party shall be the Federal Funds Effective Rate as defined in Section VI of this Paragraph 10.

IX.

Other Changes. The following changes to the Collateral Annex shall be applicable. A.

Introduction. The first paragraph of the introduction is amended to read as follows: “This Collateral Annex, together with the Paragraph 10 Cover Sheet, (the “Transition Collateral Annex”) supplements, forms a part of, and is subject to the EEI Master Power Purchase and Sale Agreement dated as of October 15, 2012 between Kern River Cogeneration Company (“Party A”) and Southern California Edison Company (“Party B”), including the Cover Sheet and any other annexes thereto (as amended and supplemented from time to time, the “Agreement”). Capitalized terms used in this Transition Collateral Annex but not defined herein shall have the meanings given such terms in the Agreement.”

B.

Paragraph 1. Definitions. Amend Paragraph 1 as follows: i. The definition of “Credit Rating” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.12 of the Transition Master Agreement as modified in the Cover Sheet. ii. The definition of “Credit Rating Event” is amended by replacing “6(a)(iii)” with “6(a)(ii)”. iii. The definition of “Downgraded Party” is amended by replacing “6(a)(i)” with “6(a)(ii)”. iv. The definition of “Letter of Credit” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.27 of the Transition Master Agreement as modified in the Cover Sheet. v. The definition of “Letter of Credit Default” is amended by replacing the word “or” in the third line with the word “and”. vi. The definition of “Local Business Day” is amended by replacing the word “day” with “Business Day”. vii. The definition of “Notification Time” is amended by replacing “11:00, New York” with “10:00 a.m. Pacific Prevailing.” viii. The definition of “Performance Assurance” is amended by replacing “6(a)(iv)” with “6(a)(iii)”. ix. The definition of “Qualified Institution” is amended as follows:

7

“ “Qualified Institution” means a commercial bank or trust company organized under the laws of the United States or a political subdivision thereof, with (i) a Credit Rating of at least (a) "A-" by S&P, "A3" by Moody's, and “A-” by Fitch, if such entity is rated by all three Ratings Agencies; or (b) "A-" by S&P, "A3" by Moody's, or “A-” by Fitch, if such entity is rated by only two Ratings Agencies, and (ii) having a capital surplus of at least ONE BILLION AND 00/100 DOLLARS ($1,000,000,000.00).” x. The definition of “Reference Market-maker” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.71 of the Transition Master Agreement as modified in the Cover Sheet. xi. The definition of “Secured Party” is amended by replacing “3(b)” with “3(a)”. C.

Paragraph 3. Calculations of Collateral Requirement. In Paragraph 3(b)(2), is amended by replacing the comma after “Secured Party” with “and” and by deleting the phrase “, and any Interest Amount that has not yet been Transferred to the Pledging Party”.

D.

Paragraph 4. Delivery of Performance Assurance. In Paragraph 4, the penultimate sentence is amended by replacing the words “next Local Business Day” with “third Local Business Day thereafter” in clause (i), and by replacing the word “second” with fourth” in clause (ii).

E.

Paragraph 5. Reduction and Substitution of Performance Assurance. Amend Paragraph 5 as follows: i. Paragraph 5(a) is amended by deleting the parenthetical “(but no more frequently than weekly with respect to Letters of Credit and daily with respect to Cash)” from the first line. ii. The sixth sentence of Paragraph 5(a) is amended by inserting the word “Local” before “Business Day,” in clause (i) of that sentence.

F.

Paragraph 6. Administration of Performance Assurance. Amend Paragraph 6 as follows: i. Paragraph 6(a)(ii)(A) is amended by inserting “(other than subparagraph (B) below)” after “the provisions of this Paragraph 6(a)(ii)” in the first line thereof. ii. Paragraph 6(a)(ii)(B) is amended by replacing “Non-Downgraded Party” with “Downgraded Party”. iii. Paragraph 6(b)(iv) is amended by capitalizing the second instance of the word “cash” in the second sentence. iv. Paragraph 6(b)(v) is amended by replacing the parenthetical phrase “(including but not limited to the reasonable costs, expenses, and attorneys’ fees of the Secured Party)” with “(excluding attorneys’ fees)”.

G.

Paragraph 7. Exercise of Rights Against Performance Assurance. Paragraph 7(b) is amended by deleting it in its entirety and inserting the words “Intentionally Omitted.”.

H.

Paragraph 8. Disputed Calculations. Amend Paragraph 8 as follows: i. Paragraph 8(a) is amended by adding in the third sentence the phrase “and, provided further, that if no quotations can be obtained, then the Secured Party’s original calculation shall be used” immediately after the words “then that quotation shall be used” and before the “)”. ii. Paragraph 8(b) is amended by (1) adding the words “requested by the Pledging Party” between the word “Assurance” and the phrase “to be reduced”, and (2) adding in the third sentence the phrase “and, provided further that, if no quotations can be obtained, then the Secured Party’s

8

2012 CHP RA Capacity

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN KERN RIVER COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY This confirmation letter (“Confirmation”) confirms the Transaction between Kern River Cogeneration Company (“Seller” or “Kern River”) and Southern California Edison Company (“Buyer” or “SCE”), each individually a “Party” and together the “Parties”, dated as of October 15, 2012, (the “Confirmation Effective Date”) in which Seller agrees to provide to Buyer the right to the Product. This Transaction is governed by the Edison Electric Institute Master Power Purchase and Sale Agreement between the Parties, effective as of October 15, 2012, along with the Cover Sheet (the “Transition Cover Sheet:”), any amendments and annexes thereto (the “Transition Master Agreement”), and including Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement”. Capitalized terms used but not otherwise defined in this Confirmation have the meanings ascribed to them in the Transition EEI Agreement, or the Tariff (defined herein below). RECITALS A.

Seller owns and operates Generating Unit # 1 and Generating Unit # 3, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement;

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement; and

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition Tolling Confirmation and the Transition PPA.

ARTICLE 1 DEFINITIONS “Applicable Laws” means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Body having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. “Availability Incentive Payments” has the meaning set forth in the Tariff. “Availability Standards” has the meaning set forth in the Tariff. “Buyer" has the meaning specified in the introductory paragraph hereof. “CAISO” means the California Independent System Operator or any successor entity performing the same functions. “Capacity Attributes” means, with respect to a Generating Unit, any and all of the following, in each case which are attributed to or associated with the Generating Unit at any time throughout the Delivery Period: (a)

resource adequacy attributes, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward RAR;

(b)

resource adequacy attributes or other locational attributes for the Generating Unit related to a Local Capacity Area, as may be identified from time to time by the CPUC, CAISO or other Governmental Body having jurisdiction, associated with the physical location or

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2012 CHP RA Capacity

point of electrical interconnection of the Generating Unit within the CAISO Control Area, that can be counted toward a Local RAR; (c)

flexible capacity resource adequacy attributes for the Generating Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward Flexible RAR; and

(d)

other current or future defined characteristics, certificates, tags, credits, or accounting constructs, howsoever entitled, including any accounting construct counted toward any RAR, Local RAR or Flexible RAR.

“Capacity Flat Price” means the price specified in the Capacity Flat Price Table in Section 4.1. “Capacity Replacement Price” means the market price for the quantity of Product not provided by Seller under this Confirmation as determined in the manner upon which market prices are determined under Section 5.2(b) of the Transition Master Agreement. For purposes of Section 1.51 of the Transition Master Agreement, “Capacity Replacement Price” shall be deemed the “Replacement Price” for this Transaction. “CHP” has the meaning set forth in Section 8.3. “Confirmation” has the meaning specified in the introductory paragraph hereof. “Confirmation Effective Date” has the meaning specified in the introductory paragraph hereof. “Contingent Firm RA Product" has the meaning specified in Section 2.3 hereof. “Contract Price” means, for any Showing Month, the Capacity Flat Price. “Contract Quantity” has the meaning set forth in Section 2.5 and means the total Unit Quantity for all Generating Units. “CPUC Approval” means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of this Confirmation, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. “CPUC Decisions” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 06-04-040, 06-06-064, 0607-031, 07-06-029, 08-06-031, 09-06-028, 10-06-036, 11-06-022, 12-06-025, and any other existing or subsequent decisions, resolutions, or rulings related to resource adequacy, including, without limitation, the CPUC Filing Guide, in each case as may be amended from time to time by the CPUC. “CPUC Filing Guide” is the annual document issued by the CPUC which sets forth the guidelines, requirements and instructions for LSE’s to demonstrate compliance with the CPUC’s RA program. “Delivery Period” has the meaning specified in Section 2.4. “FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at marketbased rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. “Firm RA Product" has the meaning specified in the Section 2.2 hereof.

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2012 CHP RA Capacity

“Flexible RAR” means the flexible capacity requirements, including, without limitation, maximum continuous ramping, load following, and regulation, established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Flexible RAR may also be known as ramping, maximum ramping, maximum continuous ramping, maximum continuous ramping capacity, maximum continuous ramping ramp rate, load following, load following capacity, load following ramp rate, regulation, regulation capacity, and/or regulation ramp rate. “Flexible RAR Showings” means the Flexible RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. “GADS” means the Generating Availability Data System, or its successor. “Generating Facility” means the power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. For purposes of this Confirmation, the Generating Facility shall include Generating Unit # 1 and Generating Unit # 3 for the Delivery Period set forth in Section 2.4. “Generating Unit” or “Generating Units” shall mean the generation assets described in Appendix A (including any Replacement Units), from which Product is provided by Seller to Buyer. Unless otherwise stated in this Confirmation, references to Generating Unit or Generating Units shall be applicable only to Generating Until # 1 and Generating Unit # 3 throughout the Delivery Period. “Generating Unit # 1” means the Generating Unit described in Appendix A(a). “Generating Unit # 3” means the Generating Unit described in Appendix A(c). “Governmental Body” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal. “Local Capacity Area” has the meaning set forth in the Tariff. “Local RAR” means the local resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Local RAR may also be known as local area reliability, local resource adequacy, local resource adequacy procurement requirements, or local capacity requirement in other regulatory proceedings or legislative actions. “Local RAR Showings” means the Local RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. “LSE” means load-serving entity. “Monthly Delivery Period” means each calendar month during the Delivery Period and shall correspond to each Showing Month. “Monthly Payment” has the meaning specified in Section 4.1. “NERC” means the North American Electric Reliability Corporation, or its successor. “NERC/GADS Protocols” means the GADS protocols established by NERC, as may be updated from time to time. “Net Qualifying Capacity” has the meaning set forth in the Tariff. “Non-Availability Charges” has the meaning set forth in the Tariff.

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2012 CHP RA Capacity

“Outage” means any disconnection, separation or reduction in the capacity of any Generating Unit, other than a Planned Outage but including, without limitation, any such disconnection, separation or reduction in capacity that is designated as either forced or unplanned pursuant to the Tariff or the NERC/GADS Protocols. “Outage Schedule” has the meaning specified in Section 7.1. “Planned Outage” means an Approved Maintenance Outage (as defined in the Tariff), but does not include a RA Maintenance Outage with Replacement (as defined in the Tariff), a Short-Notice Opportunity RA Maintenance Outage (as defined in the Tariff) or an Off-Peak Opportunity RA Maintenance Outage (as defined in the Tariff). “Power Rating” means the electrical power output value indicated on the generating equipment nameplate. “Product” means the Capacity Attributes of the Generating Unit, provided that: (a)

Product does not include any right to the energy or ancillary services from the Generating Units;

(b)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Local Capacity Areas that results in a decrease or increase in the amount of Capacity Attributes related to a Local Capacity Area provided hereunder will not result in a change in payments made pursuant to this Transaction;

(c)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Flexible RAR, Capacity Attributes related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR, that results in a decrease or increase in the amount of Capacity Attributes related to Flexible RAR provided hereunder will not result in a change in payments made pursuant to this Transaction;

(d)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Local Capacity Areas whereby the a Generating Unit subsequently qualifies for a Local Capacity Area, the Product shall include all Capacity Attributes related to such Local Capacity Area; and

(e)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Flexible RAR, Capacity Attributes related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR whereby the a Generating Unit subsequently qualifies for to satisfy Flexible RAR, the Product shall include all Capacity Attributes related to Flexible RAR.

“PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. “Qualifying Facility” means an electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of self-certification pursuant to 18 CFR Part 292.207(a). “RAR” means the resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. “RAR Showings” means the RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. “Replacement Capacity” has the meaning specified in Section 5.2. “Replacement Unit” means a generating unit meeting the requirements specified in Section 5.1.

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2012 CHP RA Capacity

“Resource Category” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “Resource ID” has the meaning set forth in the Tariff. “Scheduling Coordinator” or “SC” has the meaning set forth in the Tariff. “Settlement Agreement” means the Qualifying Facility and Combined Heat and Power Program Settlement Agreement, approved by the CPUC in Decision 10-12-035 issued on December 21, 2010, effective November 23, 2011. “Seller” has the meaning specified in the introductory paragraph hereof. “Shortfall Capacity” has the meaning set forth in Section 3.4. “Showing Month” shall be the calendar month of the Delivery Period that is the subject of the RAR Showing, Local RAR Showing or Flexible RAR Showing, in each case, as set forth in the CPUC Decisions and outlined in the Tariff. For illustrative purposes only, pursuant to the Tariff and CPUC Decisions in effect as of the Confirmation Effective Date, the monthly RAR Showing made in June is for the Showing Month of August. “Substitute Capacity” has the meaning set forth in Section 10.1. “Substitution Rules” has the meaning set forth in Section 10.2. “Supply Plan” has the meaning set forth in the Tariff. “Tariff” means the tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. “Term” shall have the following meaning: The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied. “Transition Agreement” has the meaning specified in the introductory paragraph hereof. “Transition Collateral Annex” has the meaning specified in the introductory paragraph hereof. “Transition Cover Sheet” has the meaning specified in the introductory paragraph hereof. “Transition Master Agreement” has the meaning specified in the introductory paragraph hereof. “Transition PPA” has the meaning set forth in the Transition Cover Sheet. “Transition Tolling Confirmation” means that certain Tolling Confirmation of even date herewith between Seller and Buyer, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. “Unit NQC” means the Net Qualifying Capacity set by the CAISO for the applicable Generating Unit. The Parties agree that if the CAISO adjusts the Net Qualifying Capacity of a Generating Unit after the Confirmation Effective Date, that for the period in which the adjustment is effective, the Unit NQC shall be deemed the lesser of (i) the Unit NQC as of the Confirmation Effective Date, or (ii) the CAISO-adjusted Net Qualifying Capacity. “Unit Quantity” means the amount of Product (in MWs) provided by Seller to Buyer by each individual Generating Unit identified in Section 2.5 during the portions of the Delivery Period the Generating Unit is subject to the obligations of this Confirmation and subject to reductions as outlined in Section 3.2.

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ARTICLE 2 TRANSACTION 2.1 2.2

[Intentionally omitted] Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity for each day of each month of the Delivery Period If the Generating Units are not available to provide the full amount of the Contract Quantity for each day of a Showing Month for any reason, including without limitation any Outage or Planned Outage or any adjustment of the Capacity Attributes of any Generating Unit, Seller shall provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1 hereof. If Seller fails to provide Buyer with Replacement Capacity from Replacement Units pursuant to Section 5.1, then Seller shall be liable for damages and/or to indemnify Buyer for penalties or fines pursuant to the terms of Article Five. The Parties agree that Section 3.2 shall not apply if this Section 2.2 has been elected. 2.3

Contingent Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity for each day of each month of the Delivery Period. If the Generating Units are not available to provide the full amount of the Contract Quantity for each day of a Showing Month, Seller may elect to provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1. In such case, if Seller elects to provide Replacement Capacity pursuant to Section 5.1 and fails or if Seller elects not to provide such Replacement Capacity, then Seller shall be liable for damages and/or shall indemnify Buyer for penalties or fines pursuant to the terms of Article Five. If the Generating Units provide less than the full amount of the Contract Quantity in the event of a Planned Outage or a reduction to Unit NQC, Seller is not obligated to provide Buyer with Replacement Capacity and shall not be liable for damages or obligated to indemnify Buyer for penalties or fines pursuant to Article 5 hereof. Notwithstanding anything to the contrary set forth in this Confirmation, Seller has no obligation to deliver, and Buyer has no obligation to make a Monthly Payment for the Product for the Monthly Delivery Period if the Showing Month for the applicable month occurred before CPUC Approval. 2.4

Delivery Period

The “Delivery Period” shall be: the later of (a) October 15, 2012, or (b) the date when this Agreement has received both CPUC Approval and FERC Approval; provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition Tolling Confirmation and the Transition PPA have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), through June 30, 2015. 2.5

Contract Quantity

The Contract Quantity for each day of each applicable Showing Month is as follows:

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2012 CHP RA Capacity

Generating Unit # 1 Contract Quantity (MWs) Showing Month

2012

Generating Unit # 3 Contract Quantity (MWs)

2013

2014

2015

January

77

77

77

February

77

77

March

77

April

Showing Month

2012

2013

2014

2015

January

77

77

77

77

February

77

77

77

77

77

March

77

77

77

77

77

77

April

77

77

77

May

77

77

77

May

77

77

77

June

77

77

77

June

77

77

77

July

77

77

July

77

77

August

77

77

August

77

77

September

77

77

September

77

77

October

77

77

77

October

77

77

77

November

77

77

77

November

77

77

77

December

77

77

77

December

77

77

77

ARTICLE 3 DELIVERY OBLIGATIONS 3.1

Delivery of Product

Subject to any reductions set forth in Section 3.2 (if Section 2.3 above is selected), Seller shall provide Buyer with the Contract Quantity of Product for each day of each Showing Month consistent with the following: (a)

Seller shall, on a timely basis, submit, or cause each Generating Unit's SC to submit, Supply Plans in accordance with the Tariff to identify and confirm the Unit Quantity provided to Buyer for each day of each Showing Month so that the total amount of Unit Quantity identified and confirmed for each day of such Showing Month equals the Contract Quantity for such day of such Showing Month, unless specifically requested not to do so by the Buyer.

(b)

Seller shall cause each Generating Unit’s SC to submit written notification to Buyer, no later than fifteen (15) Business Days before the relevant deadline for any applicable RAR Showing, Local RAR Showing or Flexible RAR Showing, that Buyer will be credited with the Unit Quantity for each day of the Showing Month in the Generating Unit’s SC Supply Plan so that the total amount of Unit Quantity for each day of such Showing Month credited equals the Contract Quantity.

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2012 CHP RA Capacity

3.2

Adjustments to Contract Quantity

In the event that Section 2.3 is applicable, then: (a)

Seller’s obligation to deliver the Contract Quantity of Product for each day of each Showing Month may be reduced if any portion of the Generating Unit(s) is scheduled for a Planned Outage during that month for the applicable days of such Planned Outage; provided, Seller notifies Buyer, no later than fifteen (15) Business Days before the relevant deadline for the corresponding RAR Showing, Local RAR Showing or Flexible RAR Showing applicable to that Showing Month, the amount of Product from each Generating Unit Buyer is permitted to include in Buyer’s RAR Showing, Local RAR Showing or Flexible RAR Showing applicable to that month as a result of such Planned Outage. In the event Seller is unable to provide the Contract Quantity for any portion of a Showing Month because of a Planned Outage of a Generating Unit, Seller has the option, but not the obligation, to provide Product from Replacement Units; provided, Seller provides and identifies such Replacement Units consistent with Section 5.1. In addition, if Seller chooses not to provide Product from Replacement Units and a Generating Unit is on a Planned Outage for any portion of the applicable Showing Month, then, the Contract Quantity shall be revised in accordance with any applicable adjustments stipulated by the CPUC Filing Guide or CAISO guidelines in effect for the applicable portion of the Showing Month in which the Planned Outage occurs.

(b)

3.3

Reductions in Unit NQC: In the event the Generating Unit experiences a reduction in Unit NQC as determined by the CAISO; Seller has the option, but not the obligation, to provide the Unit Quantity from the same Generating Unit; provided the Generating Unit has sufficient remaining and available Product.

Buyer’s Re-Sale of Product

Buyer may re-sell all or a portion of the Product acquired hereunder. 3.4

Post-Showing Replacement Capacity

In the event CAISO determines, in accordance with the Tariff, that any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any portion of a Showing Month which was shown by Buyer in its RAR Showings, Local RAR Showings or Flexible RAR Showings requires outage replacement in accordance with Section 40.7 of the Tariff (“Shortfall Capacity”), (i) Seller’s Monthly Payment will be reduced in accordance with Section 4.1 below and, neither Seller, nor the Generating Unit’s SC (unless the Generating Unit’s SC is Buyer), shall have the right to provide Buyer with RA Replacement Capacity with respect to such Shortfall Capacity, (ii) Seller shall have no liability under Sections 5.2 or 5.3 below with respect to such Shortfall Capacity, except to the extent described in Section 10.3 below and (iii) Seller shall have no liability to Buyer for any costs which are allocated to Buyer by the CAISO for any RA Maintenance Outage Backstop Capacity procured by CAISO which was related to such Shortfall Capacity, except to the extent described in Section 10.3 below. Notwithstanding anything to the contrary in this Agreement, at any time that any of the proposed amendments to the Tariff relating to outage replacement, filed by the CAISO at FERC on September 20, 2012 (Docket ER 12-2669-000), have not been authorized by FERC, the provisions of this Section 3.4 shall not be applicable, and, for purposes of calculating Seller’s Monthly Payment under Section 4.1, “D” (Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month) shall equal zero.

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2012 CHP RA Capacity

ARTICLE 4 PAYMENT 4.1

Monthly Payment

In accordance with the terms of Article Six of the Transition Master Agreement, Buyer shall make a Monthly Payment to Seller for each Generating Unit, after the applicable Showing Month, as follows:

Monthly Payment = (A x B x 1,000) where: A = applicable Contract Price for that Showing Month B= C = Contract Quantity provided by Seller to Buyer pursuant to and consistent with Section 3.1 for the applicable day of the Showing Month D = Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month i = Each day of Showing Month n = number of days in the Showing Month The Monthly Payment calculation shall be rounded to two decimal places. CAPACITY FLAT PRICE TABLE

4.2

Contract Year

RA Capacity Flat Price ($/kW-month)

2012

1.18

2013

1.18

2014

1.18

2015

1.18

Allocation of Other Payments and Costs (a)

Seller shall retain any revenues it may receive from and pay all costs charged by the CAISO or any other third party with respect to any Generating Unit for (i) start-up, shutdown, and minimum load costs, (ii) capacity revenue for ancillary services, (iii) energy sales, and (iv) any revenues for black start or reactive power services.

(b)

Buyer shall be entitled to receive and retain all revenues associated with the Contract Quantity of Product during the Delivery Period (including any capacity revenues from RMR Contracts for any Generating Unit, Capacity Procurement Mechanism (CPM), or its successor, and Residual Unit Commitment (RUC) Availability Payments, or its successor, but excluding payments described in Section 4.2(a)(i)-(iv) above).

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2012 CHP RA Capacity

(c)

In accordance with Section 4.1 of this Confirmation and Article Six of the Transition Master Agreement, (i) all such Buyer revenues described in this Section 4.2, but received by Seller, or a Generating Unit’s SC, owner, or operator shall be remitted to Buyer, and Seller shall pay such revenues to Buyer if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Buyer. If Seller fails to pay such revenues to Buyer, Buyer may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts Buyer may owe to Seller under this Confirmation. In order to verify the accuracy of such revenues, Buyer shall have the right, at its sole expense and during normal working hours after reasonable prior notice, to hire an independent third party reasonably acceptable to Seller to audit any documents, records or data of Seller associated with the Contract Quantity; and (ii) all such Seller, or a Generating Unit’s SC, owner, or operator revenues described in this Section 4.2, but received by Buyer shall be remitted to Seller, and Buyer shall pay such revenues to Seller if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Seller. If Buyer fails to pay such revenues to Seller, Seller may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts it may owe to Buyer under this Confirmation.

(d)

If a centralized capacity market develops within the CAISO region, Buyer will have exclusive rights to offer, bid, or otherwise submit the Contract Quantity provided to Buyer pursuant to this Confirmation for re-sale in such market, and retain and receive any and all related revenues.

(e)

Seller agrees that the Generating Units are subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account.

ARTICLE 5 SELLER'S FAILURE TO DELIVER CONTRACT QUANTITY 5.1

Seller’s Duty To Provide Replacement Capacity

Subject to any adjustments made pursuant to Section 3.2(a) (if Section 2.3 above is selected), if Seller is unable to provide the full Contract Quantity of Product for day of any Showing Month, then: (a)

Seller may, at no cost to Buyer, provide Buyer with replacement Product from one or more Replacement Units, such that the total amount of Product provided to Buyer from all Generating Units and Replacement Units for each day of the Showing Month equals the Contract Quantity; provided, that (i) replacement Product from any generating unit other than the generating units described in Section 5.1(a)(ii) may only be provided with Buyer’s consent, which may not be unreasonably or untimely withheld, and (ii) replacement Product from any of Seller’s generating units subject to the Transition PPA may only be provided with Buyer’s consent, which Buyer may give or withhold in Buyer’s sole discretion; and

(b)

Seller shall identify Replacement Units meeting the above requirements no later than fifteen (15) Business Days before the relevant deadline for Buyer's RAR Showing, Local RAR Showing and/or Flexible RAR Showing, provided, that the designation of any Replacement Unit by Seller shall be subject to Buyer’s prior written approval. Once

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2012 CHP RA Capacity

Seller has identified in writing any Replacement Units that meet the requirements of this Section 5.1, any such Replacement Unit shall be automatically deemed a Generating Unit for purposes of this Confirmation for that Showing Month. 5.2

Damages for Failure to Provide Replacement Capacity

If either Section 2.2 or 2.3 is selected above and Seller fails to provide Buyer any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any day of any Showing Month or if Seller has elected to provide replacement Product in accordance with the terms of this Confirmation, but fails to provide such replacement Product from one or more Replacement Units for any Showing Month, then, in each case, the following shall apply:

5.3

(a)

Buyer may, but shall not be required to, replace any portion of the Contract Quantity not provided by Seller for any portions of each Showing Month with capacity having equivalent Capacity Attributes as the Product not provided by Seller (“Replacement Capacity”). Buyer may enter into purchase transactions with one or more parties to replace the portion of Contract Quantity not provided by Seller for all portions of each Showing Month. Additionally, Buyer may enter into one or more arrangements to repurchase its obligation to sell and deliver the capacity to another party, and such arrangements shall be considered the procurement of Replacement Capacity. Buyer shall act in a commercially reasonable manner in procuring any Replacement Capacity.

(b)

Seller shall pay to Buyer at the time set forth in Section 4.1 of the Transition Master Agreement, the following damages in lieu of damages specified in Section 4.1 of the Transition Master Agreement: an amount equal to the positive difference, if any, between (i) the sum of (A) the actual cost paid by Buyer for any Replacement Capacity, including any transaction costs and expenses incurred in connection with such procurement, plus (B) each Capacity Replacement Price times the aggregate amount of the Contract Quantity neither provided by Seller nor purchased by Buyer for all portions of the applicable Showing Month pursuant to Section 5.2(a), and (ii) the aggregate amount of Contract Quantity not provided for all applicable portions of the applicable Showing Month times the Contract Price for that month. If Seller fails to pay these damages, then Buyer may offset those damages owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement.

Indemnities for Failure to Deliver Contract Quantity

Subject to any adjustments made pursuant to Section 3.2(a), Seller agrees to indemnify, defend and hold harmless Buyer from any penalties, fines or costs assessed against Buyer by the CPUC or the CAISO, resulting from any of the following: (a)

Seller’s failure to provide any portion of the Contract Quantity, if Seller fails to replace the shortfall in Contract Quantity from Replacement Units in accordance with Section 5.1 for any portion of the Delivery Period;

(b)

Seller’s failure to provide notice of the non-availability of any portion of the Contract Quantity for any portion of the Delivery Period as required under Section 3.1; or

(c)

A Generating Unit’s SC’s failure to timely submit Supply Plans that identify Buyer’s right to the Unit Quantity purchased hereunder for each day of the Delivery Period.

With respect to the foregoing, the Parties shall use commercially reasonable efforts to minimize such penalties, fines and costs; provided, that in no event shall Buyer be required to use or change its utilization of its owned or controlled assets or market positions to minimize these penalties and fines. Seller will have no obligation to Buyer under this Section 5.3 in respect of the portion of Contract Quantity for which Seller has paid damages for Replacement Capacity. If Seller fails to pay those penalties, fines or costs, or fails to reimburse Buyer for those penalties, fines or costs, then Buyer may offset those penalties, fines or costs against any future amounts it may owe to Seller under this Confirmation.

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2012 CHP RA Capacity

ARTICLE 6 CAISO OFFER REQUIREMENTS Subject to Buyer’s request under Section 10.1, during the Delivery Period, except to the extent any Generating Unit is in an Outage or Planned Outage, Seller shall either schedule or cause the Generating Unit’s SC to schedule with, or make available to, the CAISO the Unit Quantity for each Generating Unit in compliance with the Tariff, and shall perform all, or cause the Generating Unit’s SC, owner, or operator, as applicable, to perform all obligations under the Tariff that are associated with the sale of Product hereunder. Buyer shall have no liability for the failure of Seller or the failure of any Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance, provided that Buyer in its capacity as SC shall remain liable for any failure by it to comply with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 7 PLANNED OUTAGES Upon the Confirmation Effective Date, thirty (30) days before the applicable year-ahead showing, and no later than January 1, April 1, July 1 and October 1 of each calendar year thereafter until the end of the Term, Seller shall submit, or cause the Generating Unit's SC to submit to Buyer, the portion of each Generating Unit's schedule of proposed Planned Outages (“Outage Schedule”) for the following twelve (12) month period or until the end of the Delivery Period, whichever is shorter. Within twenty (20) Business Days after its receipt of an Outage Schedule, Buyer shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Good Utility Practices, accommodate Buyer's requests regarding the timing of any Planned Outage. Seller or the Generating Unit's SC shall notify Buyer within five (5) Business Days of any change to the Outage Schedule.

ARTICLE 8 OTHER BUYER AND SELLER COVENANTS 8.1

Seller’s and Buyer’s Duty to Take Action to Allow the Utilization of the Product

Buyer and Seller shall, throughout the Delivery Period, take all commercially reasonable actions and execute any and all documents or instruments reasonably necessary to ensure Buyer's right to the use of the Contract Quantity for the sole benefit of Buyer's RAR, Local RAR and Flexible RAR, if applicable. The Parties further agree to negotiate in good faith to make necessary amendments, if any, to this Confirmation to conform this Transaction to subsequent clarifications, revisions, or decisions rendered by the CPUC, FERC, CAISO or other Governmental Body having jurisdiction to administer RAR, Local RAR or Flexible RAR, to maintain the benefits of the bargain struck by the Parties on the Confirmation Effective Date.

8.2

Seller’s Represents, Warrants and Covenants

Seller represents, warrants and covenants to Buyer that, throughout the Delivery Period and to the extent such Generating Unit is then subject to the obligations of this Confirmation: (a)

Seller owns or has the exclusive right to the Product sold under this Confirmation from each Generating Unit, and shall furnish Buyer, CAISO, CPUC or other Governmental Body with such evidence as may reasonably be requested to demonstrate such ownership or exclusive right;

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2012 CHP RA Capacity

8.3

(b)

No portion of the Contract Quantity has been committed by Seller to any third party in order to satisfy RAR Local RAR or Flexible RAR or analogous obligations in any CAISO or non-CAISO markets, other than pursuant to an RMR Contract between the CAISO and either Seller or the Generating Unit’s owner or operator;

(c)

Each Generating Unit is connected to the CAISO Controlled Grid, is within the CAISO Control Area, and is under the control of CAISO;

(d)

Seller shall, and each Generating Unit’s SC, owner and operator is obligated to, comply with Applicable Laws, including the Tariff, relating to the Product;

(e)

If Seller is the owner of any Generating Unit, the aggregation of all amounts of Capacity Attributes that Seller has sold, assigned or transferred for any Generating Unit does not exceed the Unit NQC for that Generating Unit;

(f)

Seller has notified the SC of each Generating Unit that (i) Seller has transferred the Unit Quantity with respect to each day of each Showing Month to Buyer, and (ii) the SC is obligated to deliver the Supply Plans in accordance with the Tariff;

(g)

Seller has notified the SC of each Generating Unit that Seller is obligated to cause each Generating Unit’s SC to provide to the Buyer, at least fifteen (15) Business Days before the relevant deadline for each RAR Showing, Local RAR Showing or Flexible RAR Showing, the Unit Quantity for each day of such Showing Month of each Generating Unit which is subject to the obligations of this Confirmation that is to be submitted in the Supply Plan associated with this Confirmation for the applicable period;

(h)

Seller has notified each Generating Unit’s SC that (i) Buyer is entitled to the revenues set forth in Section 4.2 and (ii) such SC is obligated to promptly deliver those revenues to Buyer, along with appropriate documentation supporting the amount of those revenues; and

(i)

Buyer shall have no liability for the failure of Seller or the failure of the Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance.

CHP Program Provisions; CPUC Approval; FERC Approval (a)

CHP Program Procurement and Seller Eligibility Seller and Buyer acknowledge and agree that Buyer is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by Buyer pursuant to this Confirmation is and shall be deemed by the Parties to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to Buyer that as of the Confirmation Effective Date, Generating Unit # 1 and Generating Unit # 3, together with the generating units that are subject to the obligations in the Transition PPA is a Qualifying Facility.

(b)

CPUC Approval (i) Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party. (ii) Failure to obtain CPUC Approval in accordance with this Section 8.3(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to

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2012 CHP RA Capacity

purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval. (c)

Provision of Information Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement.

(d)

FERC Approval (i) Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereunder, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report. (ii) Failure to obtain FERC Approval in accordance with this Section 8.3(d) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

ARTICLE 9 CONFIDENTIALITY Notwithstanding Section 10.11 of the Transition Master Agreement, the Parties agree that Buyer may disclose the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to any Governmental Body, the CPUC, the CAISO in order to support its Local RAR Showings, RAR Showings or Flexible RAR Showings, if applicable, and Seller may disclose the transfer of the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to the SC of each Generating Unit in order for such SC to timely submit accurate Supply Plans; provided, that each disclosing Party shall use reasonable efforts to limit, to the extent possible, the ability of any such applicable Governmental Body, CAISO, or SC to further disclose such information. In addition, in the

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2012 CHP RA Capacity

event Buyer resells all or any portion of the Product to another party, Buyer shall be permitted to disclose to the other party to such resale transaction all such information necessary to effect such resale transaction.

ARTICLE 10 GENERATING UNIT SUBSTITUTION 10.1

Substitute Capacity

No later than five (5) Business Days before the relevant deadline for each RAR Showing, Local RAR Showing or Flexible RAR Showing, Buyer may request that Seller not list, or cause each Generating Unit’s SC not to list, a portion or all of a Generating Unit’s Unit Quantity for any portion of a Showing Month on the Supply Plan. The amount of Unit Quantity that is the subject of such a request shall be known as “Substitute Capacity” and, for purposes of calculating a Monthly Payment pursuant to Section 4.1, be deemed Unit Quantity provided consistent with Section 3.1. Seller shall, or shall cause each Generating Unit’s SC to, comply with Buyer’s request under this Section 10.1. 10.2

Seller’s Obligations With Respect to Substitute Capacity

If Buyer makes a request for Substitute Capacity, Seller shall (a) make such Substitute Capacity available to Buyer during the applicable Showing Month in order to allow Buyer to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”); and (b) take all action, or cause each Generating Unit’s SC to take all action, to allow Buyer to utilize the Substitution Rules, including, but not limited to, ensuring that the Substitute Capacity will qualify for substitution under the Substitution Rules and providing Buyer with all information needed to utilize the Substitution Rules. Seller agrees that all Substitute Capacity that is utilized under the Substitution Rules is subject to the requirements identified in Article 6 as if the capacity had been included on the Supply Plan. 10.3

Failure to Provide Substitute Capacity

If Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitute Capacity under the Substitution Rules, then Seller shall pay for any and all Non-Availability Charges incurred by Buyer for such failure or inability to utilize the Substitution Rules; provided, that if Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitution Rules, in each case, because the Substitute Capacity does not qualify for substitution under the last sentence of Section 40.9.4.2.1(1) of the Tariff or under the last sentence of Section 40.9.4.2.1(2) of the Tariff, then Seller shall not be responsible for any such Non-Availability Charges described in this Section 10.3 associated with such inability. If Seller fails to pay any Non-Availability Charges under this Section 10.3, then Buyer may offset those charges owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement. 10.4

Notwithstanding anything to the contrary in this Confirmation, Article 10 shall not apply to this Confirmation at any time during which Buyer is the SC.

ARTICLE 11 MARKET BASED RATE AUTHORITY Seller agrees, in accordance with FERC Order No. 697, to, upon request of Buyer, submit a letter of concurrence in support of any affirmative statement by Buyer that this contractual arrangement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR § 35.42. Seller also agrees that it will not, in any filings, if any, made subject to Order Nos. 652 and 697, claim that this contractual arrangement conveys ownership or control of generation capacity from Seller to Buyer.

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2012 CHP RA Capacity

ARTICLE 12 COLLATERAL REQUIREMENTS 12.1

Seller Collateral Requirements

Notwithstanding anything to the contrary contained in the Transition Master Agreement, Seller shall provide to, and maintain with, Buyer a Full Floating Independent Amount as long as Seller or its Guarantor, if any, does not maintain Credit Ratings of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency. The Full Floating Independent Amount shall be equal to 20% of the sum of the Monthly Payments for the current month and all remaining months of the Delivery Period, without the reductions specified in Section 3.2. For the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Seller shall be added to the Exposure Amount for Buyer and subtracted from the Exposure Amount for Seller. 12.2

Current Mark-to-Market Value

The Parties further agree that for the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, the Current Mark-to-Market Value for this Transaction is deemed to be zero. If at any time prior to the expiration of the Delivery Period, a liquid market for an RA Capacity product develops wherein price quotes for such a product can be obtained, the Parties agree to amend the Confirmation to include a methodology for calculating the Current Mark-to-Market Value for this Transaction, consequently affecting the Buyer’s Exposure. 12.3

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEI Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, with respect to this Transaction only (i) if Seller has Exposure to Buyer, then the amount of Exposure for this Transaction is deemed to be zero dollars ($0), and (ii) in no event shall Buyer be required to post or maintain an Independent Amount with Seller. ARTICLE 13 OTHER 13.1

Declaration of an Early Termination Date and Calculation of Settlement Amounts

Notwithstanding anything to the contrary, the Parties shall determine the Settlement Amount for this Transaction in accordance with Section 5.2 of the Transition Master Agreement. Furthermore, with respect to this Transaction only, the following language is to be added at the end of Section 5.2 of the Transition Master Agreement: “If Buyer is the Non-Defaulting Party and Buyer reasonably expects to incur penalties, fines or costs from the CPUC, the CAISO, or any Governmental Body having jurisdiction, because Buyer is not able to include the applicable Contract Quantity in any applicable RAR Showing, Local RAR Showing or Flexible RAR Showing due to Seller’s Event of Default, then Buyer may, in good faith, estimate the amount of those penalties or fines and include this estimate in its determination of the Settlement Amount, subject to accounting to Seller when those penalties or fines are finally ascertained. If this accounting establishes that Buyer’s estimate exceeds the actual amount of penalties or fines, Buyer shall promptly remit to Seller the excess amount. The rights and obligations with respect to determining and paying any Settlement Amount or Termination Payment,

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2012 CHP RA Capacity

APPENDIX A GENERATING UNIT INFORMATION (a)

Generating Unit # 1 Name: Kern River Cogeneration Company Generating Unit # 1 Location: Bakersfield, California Resource Type: Other- Frame7E Resource Category (1, 2, 3 or 4): 4 Point of interconnection with the CAISO Controlled Grid (“Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): South Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour

(b)

Generating Unit # 3 Name: Kern River Cogeneration Company Generating Unit # 3 Location: Bakersfield, California Resource Type: Other- Frame7E Resource Category (1, 2, 3 or 4): 4 Point of interconnection with the CAISO Controlled Grid (“Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): South Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour

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MASTER POWER PURCHASE AND SALE AGREEMENT COVER SHEET This Master Power Purchase and Sale Agreement (Version 2.1; modified 4/25/00) (“Master Agreement” or “Transition Master Agreement”) is made as of the following date: October 15, 2012 (“Effective Date”). The Transition Master Agreement, together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support, margin agreement, or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the “Agreement”. The Parties to this Transition Master Agreement are the following: Name: Sycamore Cogeneration Company (“Party A”)

Name: Southern California Edison Company (“Party B”)

All Notices:

All Notices:

Street: P. O. Box 80598

Street: 2244 Walnut Grove Ave., G.O.1, Quad 1C

City: Bakersfield

Zip: 93380

City: Rosemead, CA

Zip: 91770

Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610 Duns: 18-507-4887 Federal Tax ID Number: 95-4014893

Attn: Contract Administration Phone: (626) 302-3126 Facsimile: (626) 302-8168 Duns: 006908818 Federal Tax ID Number: 95-1240335

Invoices: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Invoices: Attn: Power Procurement - Finance Phone: (626) 302-3277 Facsimile: (626) 302-3276 Email: [email protected]

Scheduling: Attn: Control Room Phone: 661-615-4704 Facsimile: 661-615-4664

Scheduling: Attn: Manager of Energy Operations Phone: (626) 302-5730 Facsimile: (626) 307-4413

Payments: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Payments: Attn: Accounts Receivable - Power Procurement Southern California Edison Company PO Box 800 Rosemead, CA 91770 Phone: (626) 302-9371 Facsimile: (626) 302-9392

Wire Transfer: BNK: JP Morgan Chase ABA: 021-0000-21 ACCT: 910-2588-705

Wire Transfer: BNK: JPMorgan Chase Bank ABA: 021000021 ACCT: 323-394434

Credit and Collections: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Credit and Collections: Attn: Manager of Credit Phone: (626) 302-3383 Facsimile: (626) 302-2517

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Confirmations: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

Confirmations: Attn: Confirmation Coordinator Phone: (626) 307-4485 Facsimile: (626) 302-3410

With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

With additional Notices of an Event of Default or Potential Event of Default to: Southern California Edison Company 2244 Walnut Grove Ave., G.O.1, Quad 1C Rosemead, CA 91770 Attn: Manager of Energy Contracts Phone: (626) 302-3312 Facsimile: (626) 302-8168

The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions: Party A Tariff

Tariff Original Volume No. 1

Party B Tariff

Tariff Original Vol. No. 8

Dated March 21, 2010 Dated 09/01/2002

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Docket Number ER10-611-000 Docket Number ER 02-2263-000

Article Two Transaction Terms and Conditions

Optional provision in Section 2.4. If not checked, inapplicable.

Article Four Remedies for Failure to Deliver or Receive

Accelerated Payment of Damages. If not checked, inapplicable.

Article Five Events of Default; Remedies

5.1(g) Cross Default for Party A: Party A: Sycamore Cogeneration Company Other Entity:

Cross Default Amount $1,000,000

Cross Default Amount $_____NA___

5.1(g) Cross Default for Party B: Party B: Southern California Edison Company.

Cross Default Amount $75,000,000

Other Entity: Not Applicable.

Cross Default Amount

5.6 Closeout Setoff Option A, as amended. Option B - Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows: Option C (No Setoff). Article Eight Credit and Collateral Requirements

8.1 Party A Credit Protection: (a) Financial Information: Option A, as amended. Option B Specify: Option C Specify:

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(b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex.

(d) Downgrade Event: Not Applicable. Applicable. If applicable, complete the following: It shall be a Downgrade Event for Party B if Party B’s Credit Rating falls below ______ from S&P or _________ from Moody's or ______ from Fitch or if Party B is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party B: Not Applicable. Guarantee Amount: Not Applicable. 8.2 Party B Credit Protection: (a) Financial Information: Option A, as amended. Option B, as amended. Specify: [Guarantor or other party specified, if applicable]________________ Option C Specify: ___________ (b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex. (d) Downgrade Event: Not Applicable. Applicable.

4

If applicable, complete the following: It shall be a Downgrade Event for Party A if Party A’s Credit Rating falls below ___ from S&P or ___ from Moody's or ______ from Fitch or if Party A is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party A: Guarantee Amount: $__________ Article Ten Confidentiality Schedule M

Confidentiality Applicable. If not checked, inapplicable. Party A is a Governmental Entity or Public Power System. Party B is a Governmental Entity or Public Power System. Add Section 3.6. If not checked, inapplicable. Add Section 8.4. If not checked, inapplicable.

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Other Changes

The following changes shall be applicable. ARTICLE ONE: GENERAL DEFINITIONS. Amend Article One as follows: Section 1.4 is amended by (i) deleting the word “or” in the first line, and (ii) inserting the words “, or the Friday immediately following the U.S. Thanksgiving holiday” immediately after “Bank holiday”. Section 1.11 is amended by (i) deleting the words “attorneys’ fees and” and (ii) inserting the words “(excluding attorneys’ fees)” after the word “expenses” in the fifth line. Section 1.12 is amended by replacing the word “issues” in the fourth line with the word “issuer”, and replacing the phrase “S&P, Moody’s or any other rating agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement” with the phrase “the Ratings Agencies”. Section 1.24 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.27 is amended to read as follows: “1.27 ‘Letter of Credit’ means an irrevocable, nontransferable standby letter of credit, issued by a major U.S. commercial bank or the U.S. branch office of a foreign bank with, in either case, a Credit Rating of at least (a) A- by S&P, A3 by Moody’s, and A- by Fitch, if such entity is rated by the Ratings Agencies; or (b) A- by S&P, A3 by Moody’s, or A- by Fitch, if such entity is rated by only one or two of the Ratings Agencies, in substantially the form attached hereto as Schedule 1, with such changes to the terms in that form as the issuing bank may require and as may be acceptable to the beneficiary thereof. Costs of a Letter of Credit shall be borne by the applicant for such Letter of Credit.” Section 1.28 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.29 is amended by inserting the words “or ‘Transition Master Agreement’ ” immediately after “Master Agreement”. Section 1.50 is amended by replacing the term “Section 2.4” with the term “Section 2.5”. Section 1.51 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, from an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Buyer’s option,” the phrase “absent a purchase from an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. Section 1.53 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, to an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Seller’s option,” the phrase “absent a sale to an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. New Sections 1.62, 1.63, 1.64, 1.65, 1.66, 1.67, 1.68, 1.69, 1.70, 1.71 and 1.72 are

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added to read as follows: “1.62 ‘CPUC Approval’ means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement and the Transition PPA in their respective entirety, including payments to be made by Party B, subject to CPUC review of Party B’s administration of each of the Agreement and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and nonappealable.” “1.63 ‘FERC Approval’ means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.7(a) of this Agreement in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal.” “1.64 ‘Fitch’ means Fitch Ratings Ltd. or its successor.” “1.65 ‘Forward Price Assessments’ means quotations solicited or obtained in good faith from regularly published and widely-distributed forward price assessments from a broker that is not an Affiliate of either Party and who is actively participating in markets for the relevant Products.” “1.66 ‘Market Quotation Average Price’ means the arithmetic mean of the quotations solicited in good faith from not less than three (3) Reference MarketMakers (as hereinafter defined); provided, however, that the Party obtaining the quotes shall use reasonable efforts to obtain good faith quotations from at least five (5) Reference Market-Makers and, if at least five (5) such quotations are obtained, the Market Quotation Average Price shall be determined by disregarding the highest and lowest quotations and taking the arithmetic mean of the remaining quotations. The quotations shall be based on the offers to sell or bids to buy, as applicable, obtained for transactions substantially similar to each Terminated Transaction. The quote must be obtained assuming that the Party obtaining the quote will provide sufficient credit support for the proposed transaction. Each quotation shall be obtained in good faith by such Party, to the extent reasonably practicable, as of the same day and time (without regard to different time zones) on or as soon as reasonably practicable after the relevant Early Termination Date, such day and time as of which those quotations will be selected shall be specified in accordance with Section 5.2. If fewer than three (3) quotations are obtained, it will be deemed that the Market Quotation Average Price in respect of such Terminated Transaction or group of Terminated Transactions cannot be determined.” “1.67 ‘Merger Event’ means, with respect to a Party or its Guarantor, that such

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Party or its Guarantor consolidates or amalgamates with, merges into or with, or transfers substantially all its assets to another entity and (i) the resulting entity fails to assume all the obligations of such Party hereunder or of such Party’s Guarantor under its guaranty, or (ii) the benefits of any credit support provided by such Party pursuant to Article Eight, or any guaranty provided by such Party’s Guarantor, fail to extend the performance by such resulting, surviving or transferee entity of its obligations hereunder, or (iii) the resulting entity’s creditworthiness is materially weaker than that of such Party or its Guarantor immediately prior to such action. The creditworthiness of the resulting entity shall not be deemed to be ‘materially weaker’ so long as the resulting entity maintains a Credit Rating of at least that of the applicable Party or its Guarantor, as the case may be, immediately prior to the consolidation, merger or transfer.” “1.68 ‘Ratings Agency’ means any of S&P, Moody’s, and Fitch, and any other ratings agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement (collectively the ‘Ratings Agencies’).” “1.69 ‘Reference Market-Maker’ means a leading dealer in the relevant market that is not an Affiliate of either Party and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker.” “1.70 ‘Specified Energy Transaction’ means the Transition PPA or any transaction (including an agreement with respect to any such transaction) now existing or hereafter entered into between Party A and Party B (or any Guarantor of such Party) which is not a Transaction under this Agreement, but which is a transaction under the International Swaps and Derivatives Association Master Agreement, the North American Energy Standards Board Base Contract for Purchase and Sale of Natural Gas, the WSPP Agreement, or under any other agreement with respect to the purchase, sale, or transfer of (a) wholesale physical electric energy or capacity; (b) wholesale physical natural gas; or (c) financial derivative products related thereto.” “1.71 ‘Transition Collateral Annex’ has the meaning set forth in Section 5.1(e).” “1.72 ‘Transition PPA’ means that certain Power Purchase and Sale Agreement, dated October 15, 2012, between Party A and Party B, as may be amended from time to time.”

ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS. Amend Article Two as follows: Section 2.1 is amended by adding the following sentence to the end thereof “Any Transaction formed and effectuated pursuant to the foregoing shall be considered a ‘writing’ or ‘in writing’ and to have been ‘signed’ by each Party or otherwise binding on the Parties.” Section 2.2 is amended to delete the second comma after the words “supplements hereto),” and before “the Party” in the second sentence. Section 2.4 is amended by (i) deleting the words “either orally or” after the phrase “Section 2.3 unless agreed to” in the second to last line thereof. Section 2.5 is amended (i) to delete the phrase “Unless a Party expressly objects to a

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Recording (defined below) at the beginning of a telephone conversation,”; (ii) by capitalizing the word “each” in the first sentence; and (iii) replacing the words “Parties to this Master Agreement” with “Parties’ trading and marketing personnel”. A new Section 2.6 is added to read as follows: “2.6 Imaged Agreement. Any original executed Transition Master Agreement, Confirmation or other related document may be photocopied and stored on computer tapes and disks (the ‘Imaged Agreement’). The Imaged Agreement, if introduced as evidence on paper, the Confirmation, if introduced as evidence in automated facsimile form, the Recording, if introduced as evidence in its original form and as transcribed onto paper or into other written format, and all computer records of the foregoing, if introduced as evidence in printed format, in any judicial, arbitration, mediation or administrative proceedings, will be admissible as between the Parties to the same extent and under the same conditions as other business records originated and maintained in documentary form. Neither Party shall object to the admissibility of the Recording, the Confirmation, or the Imaged Agreement (or photocopies of the transcription of the Recording, the Confirmation, or the Imaged Agreement) on the basis that such were not originated or maintained in documentary or written form under either the hearsay rule or the best evidence rule. However, nothing in this Section 2.6 shall preclude a Party from challenging the admissibility of such evidence on some other grounds, including, without limitation, the basis that such evidence has been materially or substantially altered from the original.” A new Section 2.7 is added to read as follows: “2.7 Conditions Precedent. (a) Within sixty (60) days of the Effective Date, Party B and Party A shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Party A nor Party B shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Party A the authority to sell the Product to Party B at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within thirty (30) calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Party B shall make best efforts to provide Party A with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within fifty (50) days after the Effective Date; provided that if Party B is unable to provide Party A with a draft of the public version of such independent evaluator report within 50 days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Party B provides Party A such independent evaluator report. (b) Within sixty (60) days after the Effective Date, Party B shall file with the CPUC the appropriate request for CPUC Approval. Party B shall

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expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Party A shall use reasonable efforts to support Party B in obtaining CPUC Approval. Party B has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party. (c) Notwithstanding Party A’s and Party B’s execution and delivery of this Agreement, no Transaction under this Agreement will be permitted or deemed valid until the Parties obtain FERC Approval and Party B obtains CPUC Approval. (d) Notwithstanding anything to the contrary set forth in this Agreement, no Transaction under this Agreement will be permitted or deemed valid until all of the condition precedents set forth in the Transition PPA have been satisfied or waived in accordance with the terms of the Transition PPA.” A new Section 2.8 is added to read as follows: “2.8 Termination Rights of the Parties; Automatic Termination. (a) If the Transition PPA is terminated before the commencement of the Term Start Date of the Transition PPA (including if such termination is due to the inability to obtain FERC Approval or CPUC Approval), then this Agreement (including any Transaction and related Confirmation entered into between Party A and Party B as of the Effective Date) will automatically terminate on the date of the termination of the Transition PPA.” ARTICLE THREE: OBLIGATIONS AND DELIVERIES. Amend Article Three as follows: A new Section 3.4 is added to read as follows: “3.4 Index Transactions. If the Contract Price for a Transaction is determined by reference to an index, then the following provisions shall be applicable to such Transaction. (a)

Market Disruption. If a Market Disruption Event occurs during a Determination Period, the Floating Price for the affected Trading Day(s) shall be determined by reference to the Floating Price specified in the Transaction for the first Trading Day thereafter on which no Market Disruption Event exists; provided, however, if the Floating Price is not so determined within three (3) Business Days after the first Trading Day on which the Market Disruption Event occurred or existed, then the Parties shall negotiate in good faith to agree on a Floating Price (or a method for determining a Floating Price), and if the Parties have not so agreed on or before the twelfth Business Day following the first Trading Day on which the Market Disruption Event occurred or existed, then the Floating Price shall be determined in good faith by taking the average of the price quotations for the relevant commodity and relevant Business Days that are obtained from no more than two (2) Reference Market-Makers selected by each Party.

(b) For purposes of this Section 3.4, the following definitions shall apply:

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(i) ‘Determination Period’ means each calendar month a part or all of which is within the Delivery Period of a Transaction. (ii) ‘Exchange’ means, in respect of a Transaction, the exchange or principal trading market specified in the relevant Transaction. (iii) ‘Floating Price’ means a price per unit in $U.S. specified in a Transaction that is based upon a Price Source. (iv) ‘Market Disruption Event’ means, with respect to any Price Source, any of the following events: (a) the failure of the Price Source to announce or publish the specified Floating Price or information necessary for determining the Floating price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading in the relevant options contract or commodity on the Exchange or in the market specified for determining a Floating Price; (c) the temporary or permanent discontinuance or unavailability of the Price Source; (d) the temporary or permanent closing of any Exchange specified for determining a Floating Price; or (e) a material change in the formula for or the method of determining the Floating Price. (v) ‘Price Source’ means, in respect of a Transaction, the publication (or such other origin of reference, including an Exchange) containing (or reporting) the specified price (or prices from which the specified price is calculated) specified in the relevant Transaction. (vi) ‘Trading Day’ means a day in respect of which the relevant Price Source published the Floating Price. (c) Corrections to Published Prices. For purposes of determining a Floating Price for any day, if the price published or announced on a given day and used or to be used to determine a relevant price is subsequently corrected and the correction is published or announced by the person responsible for that publication or announcement within twelve (12) months of the original publication or announcement, either Party may notify the other Party of (i) that correction and (ii) the amount (if any) that is payable as a result of that correction. If, not later than thirty (30) days after publication or announcement of that correction, a Party gives notice that an amount is so payable, the Party that originally either received or retained such amount will, not later than ten (10) Business Days after the effectiveness of that notice, pay, subject to any applicable conditions precedent, to the other Party that amount, together with interest at the Interest Rate for the period from and including the day on which payment originally was (or was not) made to but excluding the day of payment of the refund or payment resulting from that correction. (d) Calculation of Floating Price. For the purposes of the calculation of a Floating Price, all numbers shall be rounded to three (3) decimal places. If the fourth (4th) decimal number is five (5) or greater, then the third (3rd) decimal number shall be increased by one (1), and if the fourth (4th) decimal number is less than five (5), then the third (3rd) decimal number shall remain unchanged.” ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES. Amend Article Five as

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follows: Section 5.1(a) is amended by replacing “three (3) Business Days” with “five (5) Business Days”. Section 5.1(e) is amended by adding after the word “hereof” the phrase “or any other credit arrangement, including, but not limited to, the Collateral Annex (the ‘Transition Collateral Annex’) (or any similar agreement) related to this Agreement”. Section 5.1(f) is amended to read as follows: “(f) a Merger Event occurs with respect to such Party or its Guarantor, if applicable;” Section 5.1(h)(iv) is amended by inserting the words “made in connection with this Agreement” after the first instance of the word “guaranty”. Section 5.1(h)(v) is amended by inserting the words “made in connection with this Agreement” after the word “guaranty”. Section 5.1 is amended by adding the following Sections 5.1(i) and 5.1(j) at the end thereof: “(i) an event of default occurs (howsoever determined) under a Specified Energy Transaction (including under the Transition PPA) with respect to such Party and, after giving effect to any applicable notice requirement or grace period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that Specified Energy Transaction; or (j) the Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, this Transition Master Agreement, any Confirmation executed and delivered by that Party, the Transition PPA or any Transaction evidenced by such a Confirmation.” Section 5.2 is amended by (i) inserting “(a)” at the beginning thereof; (ii) reversing the placement of “(i)” and “to”; (iii) inserting after the words “designate a day” the words “and time of day” in clause (i) thereof; (iv) replacing the phrase “as soon thereafter as is reasonably practicable)” with “, then each such Transaction — individually, an ‘Excluded Transaction’ and collectively, the ‘Excluded Transactions’— shall be terminated as soon thereafter as is reasonably practicable, and upon termination shall be deemed to be a Terminated Transaction) and the Termination Payment payable in connection with all Terminated Transactions shall be calculated in accordance with this Section 5.2 and with Section 5.3 below”; and (v) adding the following paragraph at the end thereof: “(b) The Non-Defaulting Party shall determine its Gains and Losses by determining the Market Quotation Average Price for each Terminated Transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts, to obtain the Market Quotation Average Price with respect to any Terminated Transaction, then the NonDefaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner by calculating the arithmetic mean of at least three (3) Forward Price Assessments for transactions substantially similar to each Terminated Transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts to obtain at least three (3) Forward Price Assessments with respect to any Terminated Transaction, then the Non-Defaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a

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commercially reasonable manner by reference to information supplied to it by one or more third parties including, without limitation, index prices, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads, or other relevant market data in the relevant markets; provided, however, that the provider of such information shall not be an Affiliate of either Party. Only in the event the Non-Defaulting Party is not able, after using commercially reasonable efforts, to obtain such third party information, then the Non-Defaulting Party may calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner using relevant market data it has available to it internally.” Section 5.3 is amended by (i) deleting the “:” in the second line thereof; (ii) replacing the words “Agreement against” with “Agreement, against” immediately before “(b)”; and (iii) inserting the phrase “any cash then available to the Defaulting Party pursuant to Article Eight,” between the words “Non-Defaulting Party,” and “plus any” in the sixth line thereof. Section 5.4 is amended by inserting the phrase “but in no event more than fifteen (15) Business Days following the Early Termination Date,” after the phrase “liquidation,” in the second line thereof. Section 5.6 Option A is amended by (i) inserting the following phrase “with respect to the Specified Energy Transactions,” before the words “and/or (ii)” and (ii) adding the following at the end thereof : “Notwithstanding anything to the contrary contained in this Transition Master Agreement, or in any other agreement, instrument, or undertaking between the Parties with respect to a Specified Energy Transaction, if an Early Termination Date has been designated pursuant to Section 5.2, then, in addition to the other remedies provided in this Transition Master Agreement, the Non-Defaulting Party may accelerate, liquidate and terminate all, but not less than all, Specified Energy Transactions between the Parties.” Section 5.7 is amended to capitalize the word “early” in line 6 to read “Early”. ARTICLE SIX: PAYMENT AND NETTING. Amend Article Six as follows: Section 6.3 is amended to read as follows: “6.3 Disputes and Adjustments of Invoices. A Party may adjust any invoice rendered by it under this Agreement to correct any arithmetic or computational error or to include additional charges or claims within twenty-four (24) months after the close of the month in which the obligations being invoiced arose. A receiving Party may, in good faith, dispute the correctness of any invoice or of any adjustment to any invoice previously rendered to it by providing notice to the other Party on or before the later of (i) twelve (12) months of the date of receipt of such invoice or adjusted invoice, or (ii) twenty-four (24) months after the close of the month in which the obligation being invoiced arose. Failure to provide such notice within the time frame set forth in the preceding sentence waives the dispute with respect to such invoice. A Party disputing all or any part of an invoice or an adjustment to an invoice previously rendered to it may pay only the undisputed portion of the invoice when due, provided such Party provides notice to the other Party of the basis for and amount of the disputed portion of the invoice that has not been paid. The disputed portion of the invoice must be paid within two (2) Business Days of resolution of the dispute, along

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with interest accrued at the Interest Rate from and including the original due date of the invoice to but excluding the date the disputed portion of the invoice is actually paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment but excluding the date repaid or deducted by the Party receiving such overpayment. An invoice can only be adjusted or amended after it was originally rendered within the twenty-four (24) month time frame set forth in the first sentence of this Section 6.3. If an invoice is not rendered within twentyfour (24) months after the close of the month in which the payment obligations arose, the right to payment for that month under this Agreement is waived.” Section 6.7 is amended to replace the phrase “Section 6.1” with the phrase “Section 6.2”. ARTICLE SEVEN: LIMITATIONS. Amend Article Seven as follows: Section 7.1 is amended to (i) delete the phrase “EXCEPT AS SET FORTH HEREIN” in the first sentence; and (ii) in the fifth sentence (a) replace in its entirety the phrase “UNLESS EXPRESSLY HEREIN PROVIDED” with “NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY”; (b) add the following phrase “SET FORTH IN THIS AGREEMENT” after the words “INDEMNITY PROVISION”; and (c) add the following phrase “; PROVIDED, HOWEVER, THAT NOTHING IN THIS PROVISION SHALL AFFECT THE ENFORCEABILITY OF SECTIONS 5.2 AND 5.3 OF THIS AGREEMENT” after the words “OR OTHERWISE”. ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS. Amend Article Eight as follows: Section 8.1(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes) after the words “consolidated financial statements” in the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations, provided however, for the purposes of this (i) and (ii), if Party B’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party B’s website, then Party B shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line. Section 8.2(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes)” after the words “consolidated financial statements” in the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year end audit adjustments), provided however, for the purposes of

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this (i) and (ii), if Party A’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party A’s website, then Party A shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line; and (v) at the end thereof the phrase “For purposes of this Section, ‘Responsible Officer’ shall mean the Executive Director, Treasurer or any Assistant Treasurer of Party A or any employee of Party A designated by any of the foregoing.”. A new Section 8.4 is added to read as follows: “8.4 California Commercial Code Waiver. This Agreement and the Transition Collateral Annex set forth the entirety of the agreement of the Parties regarding credit, collateral and adequate assurances, in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement. Except as expressly set forth in the options elected by the Parties in respect of Sections 8.1 and 8.2, in Section 8.3, and in the relevant portions of the Transition Collateral Annex, neither Party: (a) has or will have any obligation to post margin, provide letters of credit, pay deposits, make any other prepayments or provide any other financial assurances, in any form whatsoever, or (b) will have reasonable grounds for insecurity with respect to the creditworthiness of a Party that is complying with the relevant provisions of Section 8 of this Transition Master Agreement and of the relevant provisions of the Transition Collateral Annex; in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement, and all implied rights relating to financial assurances arising from California Commercial Code Section 2609 or case law applying similar doctrines, are hereby waived.” ARTICLE NINE: GOVERNMENTAL CHARGES. Amend Article Nine as follows: Section 9.2, is amended to add the words “, charges, or fees” after the word “taxes” in the first line thereof. ARTICLE TEN: MISCELLANEOUS. Amend Article Ten as follows: Section 10.2(vi) is amended to add the phrase “(for purposes of this Section 10.2(vi), Party B shall be deemed to have no Affiliates)” after the word “Affiliates”. Section 10.2(x) is amended to read as follows: “(x) it is an ‘eligible commercial entity’ within the meaning of Section 1a (11) of the Commodity Exchange Act, as amended by the Commodity Futures Modernization Act of 2000 (the ‘Commodity Exchange Act’);” Section 10.2(xi) is amended to read as follows: “(xi) it is an ‘eligible contract participant’ within the meaning of Section 1a (12) of the Commodity Exchange Act; and ” Section 10.2(xii) is amended to read as follows: “(xii) each Transaction that is not executed or traded on a ‘trading facility’, as defined in Section 1(a)(33) of the Commodity Exchange Act, is subject to individual negotiation by the Parties.”

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Section 10.4 is amended by adding the following sentence at the end thereof: “Neither Party shall be liable with respect to any Claim to the extent that such Claim resulted from the negligence, willful misconduct, or bad faith of the indemnified Party.” Section 10.5 is amended as follows: (a) add the following phrase to the end of clause (i) immediately after the word “arrangements” the phrase “to any person or entity whose creditworthiness is equal to or higher than that of such Party”; (b) in clause (ii) replace the words “affiliate” and “affiliate’s” with, respectively “Affiliate” and “Affiliate’s”; and (c) in clause (iii) immediately after the words “substantially all of the assets” insert the words “of such Party and”. Section 10.6 is amended to read as follows: “10.6 Governing Law; Venue; Dispute Resolution. (a) Governing Law and Venue. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY DISPUTE ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT. The Parties hereby consent to conduct all dispute resolution, judicial actions or proceedings arising directly, indirectly or otherwise in conjunction with, out of, related to, or arising from this Agreement in Los Angeles County, California. (b) Dispute Resolution. Any and all disputes, Claims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which Disputes the Parties have been unable to resolve by informal methods, will first be submitted to mediation in accordance with the procedures described in Section 10.6(c), and if the Dispute is not resolved through mediation, then for final and binding arbitration in accordance with the procedures described in Section 10.6(d). (c) Mediation. Either Party may initiate mediation by providing notice to the other Party of a written request for mediation, setting forth a description of the Dispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the panel of neutrals from the Judicial Arbitration and Mediation Services, Inc. or any successor entity (“JAMS”), or any other mutually acceptable non-JAMS Mediator, and such proceedings shall be conducted in accordance with the laws of the State of California, without regards to principles of conflicts of laws. Such selection and scheduling will be completed within forty-five (45) days after notice of the request for mediation. Unless the Parties agree to a different arrangement, the place of the mediation shall be in Los Angeles County, California. Unless otherwise agreed to by the Parties, the mediation will not be scheduled for a date that is greater than one-hundred twenty (120) days from the date of notice of the request for mediation. The Parties covenant that they will participate in the mediation in good faith, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and

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costs will be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, will not be subject to discovery and will be confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them; provided, however, that evidence that is otherwise admissible or discoverable will not be rendered inadmissible or non-discoverable as a result of its use in the mediation. (d) Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation in accordance with Section 10.6(c) by providing notice of a demand for binding arbitration before a single, neutral arbitrator (the “Arbitrator”) at any time following the unsuccessful conclusion of the mediation provided for in Section 10.6(c). The Parties will cooperate with one another in selecting the Arbitrator within sixty (60) days after notice of the demand for arbitration and will further cooperate in scheduling the arbitration hearing to commence no later than one-hundred eighty (180) days from the date of notice of the demand. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator will be appointed as provided for in California Code of Civil Procedure Section 1281.6, in which case each candidate for Arbitrator must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator will be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon notice of a Party’s demand for binding arbitration, such Dispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, will be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regard to principles of conflicts of laws. Except as provided for in this Section 10.6(d), the arbitration will be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated. Absent the existence of such rules and procedures, the arbitration will be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration will be in Los Angeles, California, and discovery will be limited as follows: (i) before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment); (ii) the initial disclosure will occur within thirty (30) days after the initial conference with the Arbitrator or at such time as the Arbitrator may order; (iii) discovery may commence at any time after the Parties’ initial disclosure; (iv) the Parties will not be permitted to propound any interrogatories or requests

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for admissions; (v) discovery will be limited to twenty-five (25) document requests (with no subparts), three (3) lay witness depositions, and three (3) expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents); (vi) each Party is allowed a maximum of three (3) expert witnesses, excluding rebuttal experts; (vii) Within sixty (60) days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding; (viii) within thirty (30) days after the initial expert disclosure, the Parties may designate a maximum of two (2) rebuttal experts; (ix) unless the Parties agree otherwise, all direct testimony will be in form of affidavits or declarations under penalty of perjury; and (x) each Party shall make available for crossexamination at the arbitration hearing its witnesses whose direct testimony has been so submitted. The Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections3.01, 3.02, 3.03, 9.09 of the Transition PPA. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator must, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs will be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail. Until such award is made, however, the Parties will share equally in paying the costs of the arbitration.” Section 10.8 is amended to replace in the penultimate sentence thereof the phrase “twelve (12) months” with the phrase “two (2) years”. Section 10.10 is amended to read as follows: “10.10 Bankruptcy Issues. The Parties intend that (i) all Transactions constitute a ‘forward contract’ within the meaning of the United States Bankruptcy Code (the ‘Bankruptcy Code’) or a ‘swap agreement’ within the meaning of the Bankruptcy Code; (ii) all payments made or to be made by one Party to the other Party pursuant to this Agreement constitute ‘settlement payments’ within the meaning of the Bankruptcy Code; (iii) all transfers of Performance Assurance by one Party to the other Party under this Agreement constitute ‘margin payments’ within the meaning of the Bankruptcy Code and (iv) this Agreement constitutes a ‘master netting agreement’ within the meaning of the Bankruptcy Code. Each Party further agrees that, for purposes of this Agreement, the other Party is not a ‘utility’ as such term is used in 11 U.S.C. Section 366, and each Party waives and agrees not to assert the applicability of the provisions of 11 U.S.C. Section 366 in any bankruptcy proceeding wherein such Party is a debtor. In any such proceeding, each Party further waives the right to assert that the other Party

18

is a provider of last resort to the extent such term relates to 11 U.S.C. Section 366 or another provision of 11 U.S.C. Section 101-1532.” Section 10.11 is amended to read as follows: “10.11 Confidentiality. If the Parties have elected on the Cover Sheet of the Transition Master Agreement to make this Section 10.11 applicable to this Transition Master Agreement, neither Party shall disclose the terms or conditions of this Agreement to a third party (other than the Party’s or the Party’s Affiliates’ officers, directors, employees, lenders, counsel, accountants, advisors, or rating agencies who have a need to know such information and have agreed to keep such terms confidential) except (i) in order to comply with any applicable law, order, regulation, ruling, summons, subpoena, exchange rule, or accounting disclosure rule or standard, or to make any showing required by any applicable governmental authority; (ii) to the extent necessary for the enforcement of this Agreement or to implement any Transaction; (iii) as may be obtained from a non-confidential source that disclosed such information in a manner that did not violate its obligations to the non-disclosing Party or its Guarantor in making such disclosure; (iv) to the extent such disclosure to a third party is for the sole purpose of calculating a published index, so long as such third party (1) has agreed prior to the disclosure to protect the specific information disclosed from public disclosure and (2) is a party engaged in the business of collecting such information for the purpose of establishing, creating, or formulating a published index; (v) to the extent such information is or becomes generally available to the public prior to such disclosure by a Party; (vi) when required to be released in connection with any regulatory proceeding (provided that the releasing Party makes reasonable efforts to obtain confidential treatment of the information being released); or (vii) with respect to Party B, as may be furnished to its duly authorized regulatory and governmental agencies or entities, including without limitation the California Public Utilities Commission (the “CPUC”) and all divisions thereof, and to Party B’s Procurement Review Group (the “PRG”), a group of participants including members of the CPUC and other governmental agencies and consumer groups established by the CPUC in D.02-08-071 and D.03-06-071. The existence of this Agreement is not subject to this confidentiality obligation; provided that neither Party shall make any public announcement relating to this Agreement unless required pursuant to subsection (i) or (vi) of the foregoing sentence of this Section 10.11. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, this confidentiality obligation. With respect to information provided in connection with a Transaction, this obligation shall survive for a period of three (3) years following the expiration or termination of such Transaction. With respect to information provided under this Agreement, this obligation shall survive for a period of three (3) years following the expiration or termination of this Agreement. For the purposes of this Section 10.11, “Affiliate” for Party A shall mean Chevron Corporation, Chevron U.S.A. Inc., Chevron Sycamore Cogeneration Company, Western Sierra Energy Company and Edison Mission Energy and “Affiliate” for Party B shall mean Edison International; provided, however, that for Party A, "Affiliate" shall not

apply to the power marketing or trading personnel of Chevron Corporation, Chevron U.S.A. Inc., Chevron Sycamore Cogeneration Company, Western Sierra Energy Company or Edison Mission Energy.” New Sections 10.12 and 10.13 shall be added as follows: “10.12

No Agency.

19

In performing their respective obligations hereunder,

neither Party is acting, or is authorized to act, as agent of the other Party.” “10.13 Mobile Sierra Doctrine. (a) Absent the agreement of all Parties to the proposed change, the standard of review for changes to any rate, charge, classification, term or condition of this Agreement, whether proposed by a Party (to the extent that any waiver in subsection (b) below is unenforceable or ineffective as to such Party), a non-party or FERC acting sua sponte, shall be the ‘public interest’ standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the ‘Mobile Sierra’ doctrine). (b) Notwithstanding any provision of Agreement, and absent the prior written agreement of the Parties, each Party, to the fullest extent permitted by Applicable Laws, for itself and its respective successors and assigns, hereby also expressly and irrevocably waives any rights it can or may have, now or in the future, whether under Sections 205, 206, or 306 of the Federal Power Act or otherwise, to seek to obtain from FERC by any means, directly or indirectly (through complaint, investigation, supporting a third party seeking to obtain or otherwise), and each hereby covenants and agrees not at any time to seek to so obtain, an order from FERC changing any Section of this Agreement specifying any rate or other material economic terms and conditions agreed to by the Parties.” SCHEDULE P: PRODUCTS AND DEFINITIONS. Amend Schedule P as follows: The following definitions are added: “ ‘CAISO Energy’ means with respect to a Transaction, a Product under which the Seller shall sell and the Buyer shall purchase a quantity of energy equal to the hourly quantity without Ancillary Services (as defined in the Tariff) that is or will be scheduled as a schedule coordinator to schedule coordinator transaction pursuant to the applicable tariff and protocol provisions of the CAISO (as amended from time to time, the ‘Tariff’) for which the only excuse for failure to deliver or receive is an Uncontrollable Force (as defined in the Tariff).” The following products are added: “Other Products and Service Levels. If the Parties agree to a service level or product defined by a different agreement, set of rules, tariff, or protocol (herein, the ‘agreement’) (i.e., the WSPP Agreement) for a particular Transaction, then, unless the Parties expressly state and agree that all the terms and conditions of such other agreement will apply, such reference to a service level or product defined by such other agreement means that the service level or product for that Transaction is subject to the applicable regional independent system operator and/or utility reliability requirements and guidelines as well as the permitted excuses for performance, Force Majeure, Uncontrollable Forces, or other such excuses applicable to performance under such other agreement, to the extent inconsistent with the terms of this Agreement, provided, however, that all other terms and conditions of this Agreement shall and do remain applicable including, without limitation, Section 2.2; and provided, further that with respect to any Transaction for a product or service level defined by such other agreement, the methodology for

20

SCHEDULE 1 – Form of Letter of Credit ISSUE DATE: L/C NO.: __________________ ACCOUNT PARTY: ACCOUNT NAME ADDRESS CITY, STATE XXXXX-XXXX BENEFICIARY NAME ADDRESS CITY, STATE XXXXX-XXXX

AMOUNT: USD XXXX.00 (XXX AND 00/100 UNITED STATES DOLLARS)

WE HEREBY ESTABLISH THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT NO. ______________ FOR AN AGGREGATE AMOUNT NOT TO EXCEED THE AMOUNT INDICATED ABOVE, EXPIRING AT OUR COUNTERS WITH OUR CLOSE OF BUSINESS ON (DATE). THIS LETTER OF CREDIT IS AVAILABLE WITH (BANK NAME), AGAINST PRESENTATION OF YOUR DRAFT AT SIGHT DRAWN ON (BANK NAME), WHEN ACCOMPANIED BY: 1) THE ORIGINAL OF THIS LETTER OF CREDIT (OR A PHOTOCOPY OF THE ORIGINAL FOR PARTIAL DRAWINGS) AND ANY SUBSEQUENT AMENDMENTS, IF ANY; AND 2) A DRAW CERTIFICATE (SEE EXHIBIT A) PURPORTEDLY SIGNED BY ONE OF THE BENEFICIARY’S REPRESENTATIVES. BENEFICIARY SHALL BE ENTITLED TO DRAW UPON THIS LETTER OF CREDIT UP TO THE STATED AMOUNT, IN ONE OR MORE DRAWINGS; PROVIDED HOWEVER, THAT IF ANY DRAWING WOULD EXCEED THE STATED AMOUNT, BENEFICIARY SHALL BE ENTITLED TO DRAW ONLY THAT PORTION THAT WOULD NOT EXCEED THE STATED AMOUNT. ALL CORRESPONDENCE AND ANY DRAWINGS HEREUNDER ARE TO BE DIRECTED TO (BANK ADDRESS/CONTACT). WE HEREBY AGREE WITH YOU THAT DRAFTS DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS AND CONDITIONS OF THIS LETTER OF CREDIT WILL BE DULY HONORED. THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT IS ISSUED SUBJECT TO THE INTERNATIONAL STANDBY PRACTICES 1998, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 590 (ISP98) AND AS TO MATTERS NOT ADDRESSED BY THE ISP98 THIS LETTER OF CREDIT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICT OF LAWS. THE NUMBER AND THE DATE OF OUR CREDIT AND THE NAME OF OUR BANK MUST BE QUOTED ON ALL DRAFTS REQUIRED.

EXHIBIT A DRAW CERTIFICATE AN “EVENT OF DEFAULT” OR “EARLY TERMINATION DATE” (AS DEFINED IN SECTION 5 OF THE EDISON ELECTRIC INSTITUTE MASTER POWER PURCHASE & SALE AGREEMENT VERSION 2.1 AS MODIFIED ON 4/25/00 BETWEEN ACCOUNT PARTY AND BENEFICIARY, DATED _____________________ (THE “POWER PURCHASE AND SALE AGREEMENT”)) HAS OCCURRED AND IS CONTINUING WITH RESPECT TO THE ACCOUNT PARTY UNDER THIS LETTER OF CREDIT. WHEREFORE, THE UNDERSIGNED DOES HEREBY DEMAND PAYMENT TO THE UNDERSIGNED OF $USD (INSERT AMOUNT) BUT NOT TO EXCEED THE REMAINING UNDRAWN AMOUNT OF THE LETTER OF CREDIT. THE AMOUNT DEMANDED UNDER THIS LETTER OF CREDIT HAS BEEN COMPUTED IN ACCORDANCE WITH THE POWER PURCHASE AND SALE AGREEMENT.

(COMPANY NAME)

By: (SIGNATURE OF COMPANY REPRESENTATIVE) Title: _____________________________________

DATED: _________________________

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between SOUTHERN CALIFORNIA EDISON COMPANY and SYCAMORE COGENERATION COMPANY (RAP ID #2810)

Transition Standard Contract for Existing Qualifying Cogeneration Facilities

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

TABLE OF CONTENTS LIST OF EXHIBITS .......................................................................................................... iv  PREAMBLE ........................................................................................................................1  RECITALS ..........................................................................................................................1  ARTICLE ONE:  SPECIAL CONDITIONS ................................................................3  1.01  Term ................................................................................................................3  1.02  Generating Facility..........................................................................................3  1.03  Delivery Point .................................................................................................5  1.04  Capacity Performance Requirements ..............................................................5  1.05  Maintenance Outages; Major Overhaul ..........................................................5  1.06  Power Product Prices ......................................................................................5  1.07  [Intentionally omitted.] ...................................................................................6  1.08  Scheduling Coordinator Election ....................................................................6  ARTICLE TWO: SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION ......................................................7  2.01  Seller’s Satisfaction of Obligations before the Term Start Date.....................7  2.02  Termination Rights of the Parties ...................................................................8  2.03  Rights and Obligations Surviving Termination ..............................................9  2.04  CPUC Filing and Approval of this Agreement ...............................................9  2.05  FERC Filing and Approval ...........................................................................10  2.06  Commencement of Term under Confirmations ............................................10  ARTICLE THREE:  SELLER’S OBLIGATIONS .........................................................12  3.01  Conveyance of the Product; Retained Benefits ............................................12  3.02  Resource Adequacy Rulings .........................................................................13  3.03  Site Control ...................................................................................................14  3.04  Permits ..........................................................................................................14  3.05  Transmission .................................................................................................14  3.06  CAISO Relationship .....................................................................................15  3.07  Generating Facility Modifications ...............................................................15  3.08  Metering ........................................................................................................17  3.09  Telemetry System .........................................................................................18  3.10  Provision of Information ...............................................................................19  3.11  [Intentionally omitted.] .................................................................................20  3.12  Fuel Supply ...................................................................................................20  3.13  Demonstrations .............................................................................................20  3.14  Operation and Record Keeping .....................................................................20  3.15  Power Product Curtailments at Transmission Provider’s or CAISO’s Request ..........................................................................................................22  3.16  Report of Lost Output ...................................................................................23  3.17  FERC Qualifying Cogeneration Facility Status ............................................24  3.18  Notice of Cessation or Termination of Service Agreements ........................25  3.19  Buyer’s Access Rights ..................................................................................25  3.20  Seller Financial Information .........................................................................25  3.21  NERC Electric System Reliability Standards ...............................................28 

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i

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

3.22 

Allocation of Availability Incentive Payments and Non-Availability Charges .........................................................................................................29  3.23  Seller’s Reporting Requirements .................................................................30  ARTICLE FOUR:  BUYER’S OBLIGATIONS...........................................................31  4.01  Obligation to Pay ..........................................................................................31  4.02  Payment Adjustments ...................................................................................31  4.03  Payment Statement and Payment ..................................................................32  4.04  GHG Compliance Costs................................................................................35  4.05  No Representation by Buyer .........................................................................35  4.06  Buyer’s Responsibility ..................................................................................35  4.07  Buyer’s Reporting Requirements ..................................................................35  ARTICLE FIVE:  FORCE MAJEURE .......................................................................36  5.01  No Default for Force Majeure.......................................................................36  5.02  Requirements Applicable to the Claiming Party ..........................................36  5.03  Termination ...................................................................................................36  ARTICLE SIX:  EVENTS OF DEFAULT; REMEDIES .........................................37  6.01  Events of Default ..........................................................................................37  6.02  Early Termination .........................................................................................40  6.03  Termination Payment ....................................................................................40  ARTICLE SEVEN:  LIMITATIONS OF LIABILITIES ................................................42  ARTICLE EIGHT:  GOVERNMENTAL CHARGES...................................................44  8.01  Cooperation to Minimize Tax Liabilities ......................................................44  8.02  Governmental Charges..................................................................................44  8.03  Providing Information to Taxing Governmental Authorities .......................44  ARTICLE NINE:  MISCELLANEOUS ......................................................................45  9.01  Representations and Warranties ....................................................................45  9.02  Additional Representations, Warranties, and Covenants by Seller ..............46  9.03  Indemnity ......................................................................................................46  9.04  Assignment ...................................................................................................48  9.05  Consent to Collateral Assignment ................................................................49  9.06  Governing Law and Jury Trial Waiver .........................................................52  9.07  Notices ..........................................................................................................52  9.08  General ..........................................................................................................53  9.09  Confidentiality ..............................................................................................54  9.10  Insurance .......................................................................................................56  9.11  Nondedication ...............................................................................................58  9.12  Mobile Sierra ................................................................................................59  9.13  Seller Ownership and Control of Generating Facility ..................................59  9.14  Simple Interest Payments ..............................................................................59  9.15  Payments .......................................................................................................59  9.16  Provisional Relief..........................................................................................59  ARTICLE TEN:  DISPUTE RESOLUTION .............................................................61  10.01  Dispute Resolution ........................................................................................61  10.02  Mediation ......................................................................................................61 

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ii

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

10.03  Arbitration .....................................................................................................61  SIGNATURES...................................................................................................................64 

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iii

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

LIST OF EXHIBITS A.

Definitions

B.

Generating Facility and Site Description

C.

[Intentionally omitted]

D.

Monthly Contract Payment Calculation

D-1.

Force Majeure Credit Value

D-2.

Transmission Curtailment Credit Value

E.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

F.

[Intentionally omitted]

G.

Scheduling Coordinator Services

H.

[Intentionally omitted]

I.

Seller’s Forecasting Submittal and Accuracy Requirements

J.

CAISO Charges

K.

Scheduling and Delivery Deviation Adjustments

L.

Physical Trade Settlement Amount

M.

SC Trade Settlement Amount

N.

Notice List

O.

[Intentionally omitted]

P.

[Intentionally omitted]

Q.

[Intentionally omitted]

R.

Outage Schedule Submittal Requirements

S.

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

T.

QF Efficiency Monitoring Program – Cogeneration Data Reporting Form

Table of Contents

iv

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between SOUTHERN CALIFORNIA EDISON COMPANY and SYCAMORE COGENERATION COMPANY (RAP ID #2810) PREAMBLE This Power Purchase and Sale Agreement by and between Southern California Edison Company, a California corporation (“Buyer”), and Sycamore Cogeneration Company, a California general partnership (“Seller”), together with the exhibits, attachments, and any applicable referenced collateral agreement or similar arrangement between the Parties that is expressly incorporated into this Agreement by the Parties (collectively, this “Agreement”), is made, effective and binding as of October 15, 2012 (the “Effective Date”). Buyer and Seller are sometimes referred to in this Agreement individually as a “Party” and jointly as the “Parties.” Unless the context otherwise specifies or requires, initially capitalized terms used in this Agreement have the meanings set forth in Exhibit A. RECITALS A.

On or about September 20, 2007, the CPUC issued Decision (“D.”) 07-09-040 (the “Decision”) which, among other things, directed Buyer to develop a form of a standard contract and offer such contract to qualifying facilities meeting the eligibility criteria set forth in the Decision.

B.

Commencing in May 2009, Pacific Gas and Electric Company, San Diego Gas and Electric Company, Southern California Edison Company, the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, the Independent Energy Producers Association, the Division of Ratepayer Advocates of the California Public Utilities Commission, and The Utility Reform Network (collectively, the “Settling Parties”) entered into CPUC-facilitated settlement negotiations in order to resolve certain outstanding issues among the Settling Parties, including the implementation of the Decision.

Preamble; Recitals

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Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

C.

Pursuant to the settlement negotiations, the Settling Parties entered into that certain Settlement Agreement, dated October 8, 2010 (the “Settlement Agreement”), which resolved certain issues pending in Rulemakings 99-11-022, 04-04-003, 04-04-025, and 06-02-013, and Application 08-11-001.

D.

The Settlement Agreement became effective on November 23, 2011 (the “Settlement Effective Date”).

E.

Buyer is offering this Agreement to Seller in accordance with the requirements set forth in the Settlement Agreement, and Seller desires to enter into such Agreement.

G.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition EEI Agreement, including the Transition Tolling Confirmation and the Transition RA Confirmation.

H.

Pursuant to the terms and conditions set forth in the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation, Buyer will purchase from Seller and Seller will sell to Buyer the Product (as such term, in this instance only for purposes of this Agreement, is defined in each of the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation).

The Parties, intending to be legally bound, agree as follows:

Preamble; Recitals

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

ARTICLE ONE.

SPECIAL CONDITIONS

1.01

Term. The term of this Agreement (the “Term”) commences on the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained (the “Term Start Date”); provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Term shall not commence until all of the condition precedents set forth in each of the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Term Start Date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03)), and ends the date that is immediately prior to the commencement of the ‘Term’ under and as defined in the RFO Agreement, which shall be no later than June 30, 2014 (the “Term End Date”); provided, however if ‘CPUC Approval’ (as defined in the RFO Agreement) and/or ‘FERC Approval’ (as defined in the RFO Agreement) of the RFO Agreement are not obtained prior to June 30, 2014, through no fault of Seller, then the Term End Date shall be June 30, 2015. The Term Start Date must occur on the first day following the termination of the Amended and Restated Parallel Generation Agreement between Sycamore Cogeneration Company and Southern California Edison Company dated September 3, 1986, as amended and supplemented from time to time, and extended by letter agreement entered into pursuant D.07-09-040 dated June 25, 2008 (the “Existing PPA”).

1.02

Generating Facility. (a)

Name; Designation. The name of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation is Sycamore Cogeneration Company, which is an Existing Qualifying Cogeneration Facility.

(b)

Location; Site. The Generating Facility is located at SW China Grade Loop, Bakersfield, CA 93308, and is further described in Exhibit B.

(c)

Qualifying Cogeneration Facility Type. As of the Effective Date, the Generating Facility, which includes the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation, is a “topping-cycle cogeneration facility”, as defined in 18 CFR Part 292, Section 292.202(d).

(d)

Contract Capacity. As set forth in the following table, Seller may elect (i) only Firm Contract Capacity, (ii) only As-Available Contract Capacity, or (iii) both Firm Contract Capacity and As-Available Contract Capacity:

Article One

Special Conditions

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company Month January February March April May June July August September October November December

Monthly Firm Contract Capacity (kW) 152,000 151,000 151,000 149,000 149,000 148,000 147,000 147,000 147,000 149,000 151,000 152,000

As-Available Contract Capacity (kW/) 0 1,000 1,000 3,000 3,000 4,000 5,000 5,000 5,000 3,000 1,000 0

Net Contract Capacity (kW) 152,000 152,000 152,000 152,000 152,000 152,000 152,000 152,000 152,000 152,000 152,000 152,000

Firm Contract Capacity, As-Available Contract Capacity and Net Contract Capacity are subject to adjustment in accordance with Section 3.07(c). Subject to adjustment in accordance with Section 3.07(c), the Firm Contract Capacity for all months of the year must be less than or equal to 152,000 kW, the As-Available Contract Capacity for all months of the year must be less than or equal to 5,000 kW, and the sum of Firm Contract Capacity and As-Available Contract Capacity for all months of the year must be less than or equal to 152,000 kW. (e)

Expected Term Year Energy Production. (i)

The Expected Term Year Energy Production for each Term Year equals 1,280,000,000 kWh.

(ii)

The Expected Term Year Energy Production may be revised in accordance with Section 3.07(c), or based on changes in the Site Host Load or the Site Host thermal requirements; provided, however, that such revision must be supported by a certification from a California-licensed professional engineer qualified to make a representation affirming that such revision is reasonable and based on (i) actual modifications to the Generating Facility performed or to be performed by Seller in accordance with and subject to Section 3.07(c), or (ii) changes in the Site Host Load or the Site Host thermal requirements. Such certification must include all data relied on to support the revised Expected Term Year Energy Production.

(iii)

Subject to adjustments in accordance with Section 1.02(e)(ii), the Expected Term Year Energy Production may never exceed 1,280,000,000 kWh in any Term Year.

Article One

Special Conditions

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

1.03

Delivery Point. The delivery point is the point of delivery of the Power Product to the CAISO Controlled Grid which shall be between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal Magunden 230 kV line (the “Delivery Point”). Seller shall provide and convey to Buyer the Power Product from the Generating Facility at the Delivery Point. Title to and risk of loss related to the Power Product transfer from Seller to Buyer at the Delivery Point.

1.04

Capacity Performance Requirements. As further described in Exhibit D, if the Generating Facility elects to provide Firm Contract Capacity, then the Generating Facility must have a minimum Firm Contract Capacity performance requirement of 95% to earn the Maximum Firm Capacity Payment and a minimum Capacity Performance Requirement of 60% to earn any portion of the Maximum Firm Capacity Payment.

1.05

Maintenance Outages; Major Overhaul.

1.06

(a)

The total Maintenance Debit Value for Maintenance Outages, as determined in accordance with Exhibit E, may not exceed 550 hours in the first Term Year. At the end of each Term Year following the first Term Year, up to a maximum of 50 unused hours may be carried over to the following Term Year. For each of the Term Years after the first Term Year, the total Maintenance Debit Value for Maintenance Outages may not exceed 550 hours plus hours carried over from prior Term Years; provided, however, that such Maintenance Debit Value may not exceed 600 hours in any Term Year.

(b)

Seller may (i) request one Major Overhaul Allowance (in accordance with Exhibit E) of up to 750 total hours, (ii) schedule no more than one Major Overhaul; provided, however, that the Maintenance Debit Value for such Major Overhaul may not exceed 750 hours.

(c)

If Seller utilizes all of its Major Overhaul Allowance during a Major Overhaul, the remaining portion of the Major Overhaul may be converted to a Maintenance Outage as far as Maintenance Credit Value and Maintenance Debit Value are concerned; provided, however, that Seller submits a Notice to Buyer of such conversion within 60 days of the end of such Major Overhaul.

(d)

During the Peak Months, Seller may only schedule Maintenance Outages during the non-peak hours of such Peak Months, and the monthly Maintenance Debit Value for Maintenance Outages during the Peak Months may not exceed 12 nonpeak hours per Peak Month. Such limitation is part of, and not in addition to, the annual limits as set forth in Section 1.05(a).

Power Product Prices. (a)

Firm Capacity Price. The Firm Capacity Price equals $91.97 per kW-year.

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(b)

As-Available Capacity Price. The As-Available Capacity Price is set forth in Section 3 of Exhibit D.

(c)

TOD Period Energy Price. The TOD Period Energy Price is set forth in Section 2 of Exhibit D.

1.07

[Intentionally omitted.]

1.08

Scheduling Coordinator Election. Buyer is the Scheduling Coordinator under this Agreement. Notwithstanding anything to the contrary set forth in this Agreement, Buyer must be the Scheduling Coordinator under this Agreement if Seller intends to utilize the exemptions set forth in, and subject to, Sections 3.06(b) or 3.09(b). *** End of Article One ***

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ARTICLE TWO.

2.01

SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION; CPUC AND FERC APPROVAL

Seller’s Satisfaction of Obligations before the Term Start Date. Seller shall satisfy each of the following obligations before the Term Start Date: (a)

The Generating Facility is a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(b)

Seller enters into all agreements, obtains all Governmental Authority approvals and Permits, and takes all steps necessary for it to: (i)

Operate the Generating Facility;

(ii)

Deliver electric energy from the Generating Facility to the Delivery Point; and

(iii)

Schedule, or arrange for a third party or Buyer to Schedule, the electric energy produced by the Generating Facility with the CAISO;

(c)

Seller’s Scheduling Coordinator, as set forth in Section 1.08, is authorized by the CAISO to Schedule the electric energy produced by the Generating Facility with the CAISO;

(d)

Seller satisfies its obligation to install the CAISO-Approved Meters, as set forth in this Agreement;

(e)

Seller furnishes to Buyer the insurance documents required under Section 9.10(c);

(f)

Seller is in compliance with the CAISO Tariff as set forth in this Agreement;

(g)

Seller enters into and fulfills all of its obligations under (i) the applicable interconnection agreements with the applicable Transmission Provider that are required to enable Parallel Operation of the Generating Facility with the interconnected electric system and the CAISO Controlled Grid, and (ii) any transmission, distribution or other service agreement that are required to enable Seller to transmit electric energy from the Generating Facility to the Delivery Point;

(h)

Seller furnishes to Buyer the documents required under Section 3.05; and

(i)

If Buyer is Scheduling Coordinator and the Generating Facility is PIRP-eligible, then the Generating Facility is certified as a PIRP resource by the CAISO.

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2.02

Termination Rights of the Parties. (a)

[Intentionally omitted.]

(b)

Termination Right of Seller.

(c)

Article Two

(i)

Seller has the right to terminate this Agreement if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected by Buyer in a competitive solicitation. In such an instance, the termination of this Agreement will be effective as of midnight the day before the commencement of any delivery period for any electric energy, capacity or attributes from the Generating Facility which is selected by Buyer in such competitive solicitation.

(ii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected in a competitive solicitation by a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement.

(iii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility jointly enter into an agreement for the sale of electric energy, capacity or attributes with a California investorowned utility (other than Buyer) that is a party to the Settlement Agreement.

Event of Default. In the event of an uncured Event of Default or an Event of Default for which there is no opportunity for cure permitted in this Agreement, the Non-Defaulting Party may, at its option, terminate this Agreement as set forth in Section 6.02 and, if the Non-Defaulting Party is Buyer, then Seller (or any entity over which Seller or any owner or manager of Seller exercises control) agrees to waive any right it may have to enter into any new mandatory mustpurchase contract (including the Transition PPA, the QF PPA, or the Optional AsAvailable PPA, as such terms are defined in the Settlement Agreement) to sell electric energy, capacity or Related Products from the Generating Facility to Buyer or any other California investor-owned utility for a period of 365 days following the date of such termination. For purposes of this Section 2.02(c), “control” means the direct or indirect ownership of 20% or more of the outstanding capital stock or other equity interests having ordinary voting power.

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2.03

2.04

(d)

End of Term. This Agreement automatically terminates at 11:59 p.m. PPT on the Term End Date.

(e)

Failure to Obtain CPUC Approval or FERC Approval. If CPUC Approval or FERC Approval has not been obtained by the Term End Date, this Agreement shall terminate in accordance with Section 2.02(d).

(f)

Termination of the Transition EEI Agreement. If the Transition EEI Agreement is terminated before the commencement of the Delivery Period of either the Transition Tolling Confirmation or the Transition RA Confirmation (as defined therein), then this Agreement will automatically terminate, without liability for a Forward Settlement Amount by either Party, on the date of the termination of the Transition EEI Agreement.

Rights and Obligations Surviving Termination. The rights and obligations of the Parties that are intended to survive a termination of this Agreement are all such rights and obligations that this Agreement expressly provides survive such termination as well as those rights and obligations arising from either Parties’ covenants, agreements, representations or warranties applicable to, or to be performed, at, before or as a result of the termination of this Agreement, including: (a)

The obligation of Buyer to make all outstanding Monthly Contract Payments for periods before termination of this Agreement;

(b)

The obligation of Buyer to invoice Seller for all payment adjustments for periods before termination of this Agreement, as set forth in Section 4.02;

(c)

The obligation of Seller to pay any Buyer payment-adjustment invoice described in Section 4.03(b) for periods before termination of this Agreement within 30 days of Seller’s receipt of such invoice;

(d)

The obligation of Buyer or Seller, as applicable, to make payments, if any, after the termination of this Agreement, as set forth in Section 3(c) of Exhibit S;

(e)

The obligation to make a Termination Payment, as set forth in Section 6.03;

(f)

The indemnity obligations, as set forth in Section 9.03;

(g)

The obligation of confidentiality, as set forth in Section 9.09;

(h)

The right to pursue remedies under Section 6.02(c); and

(i)

The limitation of damages under Article Seven.

CPUC Filing and Approval of this Agreement.

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2.05

2.06

(a)

Within 60 days after the Effective Date, Buyer shall file with the CPUC the appropriate request for CPUC Approval. Buyer shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support Buyer in obtaining CPUC Approval. Buyer has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Before the Term Start Date, Buyer must have obtained or waived CPUC Approval.

FERC Filing and Approval. (a)

Within 60 days of the Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Buyer provides Seller such independent evaluator report.

(b)

Notwithstanding Seller’s and Buyer’s execution and delivery of this Agreement, this Agreement is subject to FERC Approval and the Term Start Date shall not occur until FERC Approval has been obtained.

Commencement of Term under Confirmations. Notwithstanding anything to the contrary set forth in this Agreement, the Term of this Agreement will not commence until the

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commencement of the Delivery Period of the Transition Tolling Confirmation and the Transition RA Confirmation (as defined respectively therein). *** End of Article Two ***

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ARTICLE THREE. SELLER’S OBLIGATIONS 3.01

Conveyance of the Product; Retained Benefits. (a)

Product. During the Term, Seller shall provide and convey the Product to Buyer in accordance with the terms of this Agreement, and Buyer shall have the exclusive right to the Product and all benefits derived therefrom, including the exclusive right to sell, convey, transfer, allocate, designate, award, report or otherwise provide any and all of the Product purchased under this Agreement and the right to all revenues generated from the use, sale or marketing of the Product.

(b)

Green Attributes. Seller hereby provides and conveys all Green Attributes associated with the Related Products as part of the Product being delivered during the Term. Seller represents and warrants that Seller holds the rights to all Green Attributes associated with the Related Products, and Seller agrees to convey and hereby conveys all such Green Attributes to Buyer as included in the delivery of the Product from the Project.

(c)

Further Action by Seller. Seller shall, at its own cost, take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term, which actions may include: (i)

Cooperating with the Governmental Authority responsible for resource adequacy administration to certify the Generating Facility for resource adequacy purposes;

(ii)

Testing the Generating Facility as may be required to certify the Generating Facility for resource adequacy purposes in accordance with the requirements set forth in the CAISO Tariff or as otherwise agreed to by the Parties;

(iii)

Committing to Buyer the Net Contract Capacity; and

(iv)

Complying with Applicable Laws regarding the registration, transfer or ownership of Green Attributes associated with the Related Products, including, if applicable to the Generating Facility, participation in WREGIS or other process recognized under Applicable Laws. With respect to WREGIS, at Buyer’s option, Seller shall cause and allow Buyer to be the “Qualified Reporting Entity” and “Account Holder” (as these two terms are defined by WREGIS) for the Generating Facility;

(v)

Complying with all CAISO Tariff requirements applicable to a Resource Adequacy Resource; and

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(vi)

(d)

3.02

If Buyer is not the Scheduling Coordinator: 1)

Timely submitting, or causing Seller’s Scheduling Coordinator to timely submit, Supply Plans to identify and confirm the Net Qualifying Capacity of the Generating Facility sold to Buyer as a Resource Adequacy Resource; and

2)

Causing the Generating Facility’s Scheduling Coordinator to certify to Buyer, within 15 Business Days before the relevant deadline for any applicable RAR Showing or LAR Showing, that Buyer will be credited with the Net Qualifying Capacity of the Generating Facility for such RAR Showing or LAR Showing in the Generating Facility’s Scheduling Coordinator’s Supply Plan.

Retained Benefits. Seller shall retain for its own use or disposition all Financial Incentives and all attributes, benefits and credits associated with the Generating Facility and the electrical or thermal energy produced therefrom, other than the Power Product and the Related Products. Subject to Seller’s compliance with the applicable FERC rules and regulations, Seller may use, provide and convey any electric energy, capacity, Green Attributes, Capacity Attributes, Resource Adequacy Benefits, or any other product or benefit associated with the Generating Facility or the output thereof before the Term Start Date.

Resource Adequacy Rulings. During the Term, Seller shall grant, pledge, assign and otherwise commit to Buyer the generating capacity of the Generating Facility associated with the Related Products in order for Buyer to use in meeting its resource adequacy obligations under any Resource Adequacy Ruling. Seller: (a)

Has not used, granted, pledged, assigned or otherwise committed any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer for any portion of the Term;

(b)

Will not during the Term use, grant, pledge, assign or otherwise commit any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer; and

(c)

Shall take all reasonable actions (including complying with all current and future CAISO Tariff provisions and decisions of the CPUC or any other Governmental Authority that address Resource Adequacy Rulings) and execute all documents that are reasonable and necessary to effect the use of the generating capacity of the Generating Facility associated with the Related Products for Buyer’s sole benefit throughout the Term.

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3.03

Site Control. Seller shall have Site Control as of the earlier of: (a) the Term Start Date and (b) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term. Seller shall provide Buyer with prompt Notice of any change in the status of Seller’s Site Control.

3.04

Permits. Seller shall obtain and maintain any and all Permits necessary for the Operation of the Generating Facility and to deliver electric energy from the Generating Facility to the Delivery Point.

3.05

Transmission. (a)

Interconnection Studies. Seller has provided Buyer with true and complete copies of all Interconnection Studies received by Seller for the Generating Facility after the date that is 24 months before the Effective Date.

(b)

Seller’s Responsibility. Seller shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable Parallel Operation of the Generating Facility with the Transmission Provider’s electric system and the applicable Control Area operator’s electric grid and to effect Scheduling of the electric energy from the Generating Facility and transmission and delivery to the Delivery Point. Except as otherwise provided in its interconnection agreement, the CAISO Tariff, or the Transmission Provider’s tariff, rules or regulations, Seller shall pay all Transmission Provider charges or other charges directly caused by, associated with, or allocated to the following:

(c)

(i)

All required Interconnection Studies, facilities upgrades, and agreements;

(ii)

Interconnection of the Generating Facility to the Transmission Provider’s electric system;

(iii)

Any costs or fees associated with obtaining and maintaining a wholesale distribution access tariff agreement, if applicable; and

(iv)

The transmission and delivery of electric energy from the Generating Facility to the Delivery Point.

Acknowledgement. The Parties acknowledge and agree that any other agreement between Seller and Buyer, including any interconnection agreements, is separate and apart from this Agreement and does not modify or add to the Parties’ obligations under this Agreement, and that any Party’s breach under such other

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agreement does not excuse such Party’s nonperformance under this Agreement, except to the extent that such breach constitutes a Force Majeure under this Agreement. 3.06

3.07

CAISO Relationship. (a)

Throughout the Term, Seller shall comply with all applicable provisions of the CAISO Tariff (including complying with any exemption obtained from the CAISO pursuant to the CAISO Tariff), as determined by the CAISO, including securing and maintaining in full force all of the CAISO agreements, certifications and approvals required in order for the Generating Facility to comply with the applicable provisions of the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.06(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not installed one or more CAISO-Approved Meters for the Generating Facility on or before the Term Start Date, Seller will not be in breach of this Agreement with respect to such requirement to install CAISOApproved Meter(s) if Seller installs such CAISO-Approved Meter(s) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement to install CAISO-Approved Meter(s) by complying with a milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to Seller’s requirement that the CAISO-Approved Meters for the Generating Facility be installed on or before the Term Start Date, which extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request.

(c)

Buyer agrees that, subject to the limitation set forth in Section 3.06(b) and upon the CAISO’s request, pending the installation of the CAISO-Approved Meter(s) by Seller for the Generating Facility, Buyer shall provide to the CAISO any settlement quality meter data reasonably requested by the CAISO for settlement purposes.

Generating Facility Modifications. (a)

Seller is responsible for the design, procurement and construction of all modifications necessary for the Generating Facility to meet the requirements of this Agreement and to comply with any restriction set forth in any Permit.

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(b)

(c)

Seller shall provide 30 days advance Notice to Buyer if there is any modification (other than a routine fluctuation in output or consumption) of the Generating Facility, the Site Host Load or operations related to the Site Host Load changing: (i)

Electric energy output by five percent of Expected Term Year Energy Production; or

(ii)

The type of Primary Fuel consumed by the Generating Facility.

Seller may not materially modify or repower the Generating Facility without prior written consent of Buyer; provided, however, that modifications or repowering will not be deemed material and is permitted under this Agreement without further consideration, other than Notices required under Section 3.07(b), if: (i)

Capacity added as a result of such modification or repower (including the addition of a steam turbine) over the Term is within the applicable MW limits set forth in the following table (for a Generating Facility with multiple turbines, the limits below are limits per turbine): Current Turbine Name Plate on the Effective Date

Increase to Turbine Name Plate Over the Term

10MW or Less

5MW

Greater than 10MW but less than 20MW

10MW

Greater than or equal to 20MW but less than 25MW

15MW

Greater than or equal to 25MW but less than 50MW

20MW

Greater than or equal to 50MW but less than 100MW

25MW

Greater than or equal to 100 but less than 200MW

35MW

Greater than or equal to 200 but less than 350MW

45MW

Greater than or equal 350MW

50MW

Or, (ii)

Such modification or repower is reasonably necessary to respond to a Force Majeure or a change in law or regulation, and a qualified Californialicensed professional engineer verifies that such modification or repower is not oversized relative to other equipment on the market. Seller shall bear the cost of such professional engineer and Seller shall secure all studies and upgrades necessitated by or associated with such modification or repower.

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3.08

(d)

Seller acknowledges that nothing in this Section 3.07 excuses Seller from any requirements of the CAISO’s interconnection process or any other applicable interconnection process.

(e)

Seller is solely responsible for all GHG Compliance Costs and all other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating Facility to the extent that such GHG Compliance Costs or other costs result from Seller’s modification or repowering of the Generating Facility in accordance with this Section 3.07.

Metering. (a)

CAISO-Approved Meter. Seller shall, at its own cost, install, maintain and test all CAISO-Approved Meters pursuant to the CAISO Tariff or other applicable metering requirements.

(b)

Check Meter. Buyer may, at its sole cost, furnish and install one Check Meter at the interconnection associated with the Generating Facility at a location designated by Seller or any other location mutually agreeable to the Parties. The Check Meter location must allow for the Check Meter to be interconnected with Buyer’s communication network to permit: (i)

Periodic, remote collection of revenue quality meter data; and

(ii)

Back-up real time transmission of operating-quality meter data through the Telemetry System set forth in Section 3.09; provided, however, that the transmission of such meter data through the Telemetry System is permitted by the CAISO.

Buyer shall test and recalibrate the Check Meter at least once every Term Year. The Check Meter will be locked or sealed, and the lock or seal shall be broken only by a Buyer representative. Seller has the right to be present whenever such lock or seal is broken. Buyer shall replace the Check Meter battery at least once every 36 months; provided, however, if the Check Meter battery fails, Buyer shall promptly replace such battery. (c)

Use of Check Meter for Back-Up Purposes. (i)

Buyer shall routinely compare the Check Meter data to the CAISOApproved Meter data.

(ii)

If the deviation between the CAISO-Approved Meter data (after adjusting (1) for all appropriate compensation and correction factors applied, if applicable, by the CAISO to the CAISO-Approved Meter, or (2) for any

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deviation that may result due to the CAISO-Approved Meter and Check Meter being physically situated in different locations) and the Check Meter data for any comparison is greater than 0.3%, Buyer shall provide Notice to Seller of such deviation and the Parties shall mutually arrange for a meter check or recertification of the Check Meter or CAISOApproved Meter, as applicable.

3.09

(iii)

Each Party shall bear its own costs for any meter check or recertification.

(iv)

Testing procedures and standards for the Check Meter will be the same as for a comparable Buyer-owned meter. Seller shall have the right to have representatives present during all such tests.

(v)

The Check Meter is intended to be used (1) for back-up purposes in the event of a failure or other malfunction of the CAISO-Approved Meter, and (2) in the event Seller has not installed the CAISO-Approved Meter, as further described in Section 3.06(b). Data from the Check Meter will only be used to validate the CAISO-Approved Meter data and, in the event of a failure or other malfunction of the CAISO-Approved Meter, or in accordance with and subject to Section 3.06(b), in place of the CAISOApproved Meter until such time that the CAISO-Approved Meter is certified.

Telemetry System. (a)

Seller is responsible for designing, furnishing, installing, maintaining and testing a real time Telemetry System in accordance with the CAISO Tariff provisions applicable to the Generating Facility. Seller has the right to request any exemption from such requirements from the CAISO so long as it is obtained pursuant to the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.09(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not complied with Section 3.09(a) on or before the Term Start Date, Seller will not be in breach of this Agreement if Seller fully complies with Section 3.09(a) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement set forth in Section 3.09(a) by complying with a milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to the requirement set forth in Section 3.09(a), which

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extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request. (c)

3.10

Buyer agrees that, subject to the limitation set forth in Section 3.09(b) and upon the CAISO’s request, pending Seller compliance with Section 3.09(a), Buyer shall provide to the CAISO any telemetry data reasonably requested by the CAISO for operating information purposes.

Provision of Information. (a)

Within 30 days after the Effective Date, Seller shall provide to Buyer (to the extent not already in Buyer’s possession), subject to Section 9.09: (i)

All currently operative agreements with providers of distribution, transmission or interconnection services for the Generating Facility and all amendments thereto;

(ii)

Any currently operative filings at FERC, including any rulings, orders or other pleadings or papers filed by FERC, concerning the qualification of the Generating Facility as a Qualifying Cogeneration Facility;

(iii)

Any Permits reasonably requested by Buyer concerning the Operation or licensing of the Generating Facility, and any applications or filings requesting or pertaining to such Permits;

(iv)

Each of the following engineering documents for the Generating Facility: 1)

Site plan drawings;

2)

Electrical one-line diagrams;

3)

Control and data acquisition details and configuration documents;

4)

Major electrical equipment specifications;

5)

Process flow diagrams;

6)

Piping and instrumentation diagrams;

7)

General arrangement drawings; and

8)

Aerial photographs of the Site, if any; and

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(v)

Instrument specifications, installation instructions, operating manuals, maintenance procedures and wiring diagrams for the CAISO-Approved Meter(s) and the Telemetry System reasonably requested by Buyer.

(b)

If applicable and subject to Section 9.09, as soon as possible, Seller shall provide to Buyer (i) engineering specifications and design drawings for the Telemetry System, and (ii) annual test reports for the CAISO-Approved Meters.

(c)

Subject to Section 9.09 and upon Buyer’s request, Seller shall make commercially reasonable efforts to provide Buyer with all documentation necessary for Buyer to comply with any discovery or data request for information from the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, which commercially reasonable efforts shall, at a minimum, include providing Buyer with all documentation regarding the operational characteristics or past performance of the Generating Facility if such documentation is requested by the CPUC.

3.11

[Intentionally omitted.]

3.12

Fuel Supply. Seller shall supply all fuel required for the Power Product and any testing or demonstration of the Generating Facility.

3.13

Demonstrations. Seller shall comply with any demonstration required for Resource Adequacy Rulings; provided, however, if such demonstrations could interfere with the operations of Seller, Seller shall be entitled to challenge such requirements with the CPUC or other relevant agency. Absent a ruling or other action granting a stay, compliance shall be required pending resolution of the challenge.

3.14

Operation and Record Keeping. Seller shall: (a)

Operate the Generating Facility in accordance with Prudent Electrical Practices;

(b)

Comply with the Forecasting requirements, as set forth in Exhibit I;

(c)

Use reasonable efforts to Operate the Generating Facility so that the Power Product conforms with the Forecast provided in accordance with Exhibit I;

(d)

Pay all CAISO Charges, as set forth in Exhibit J;

(e)

Pay all SDD Adjustments for which Seller is responsible, as set forth in Exhibit K;

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(f)

Comply with the Maintenance Outage scheduling procedures, as set forth in Exhibit E;

(g)

Comply with the Outage Schedule Submittal Requirements, as set forth in Exhibit R;

(h)

Use reasonable efforts to deliver the maximum possible quantity of As-Available Contract Capacity and associated electric energy during an Emergency Condition or a System Emergency;

(i)

Use reasonable efforts to reschedule any outage that occurs during an Emergency Condition or a System Emergency;

(j)

Keep a daily Operating log for the Generating Facility that includes information on availability, outages, circuit breaker trip operations requiring a manual reset, and any significant events related to the Operation of the Generating Facility, including: (i)

Real and reactive power production;

(ii)

Changes in Operating status;

(iii)

Protective apparatus operations; and

(iv)

Any unusual conditions found during inspections;

(k)

Keep all Operating records required of a Qualifying Cogeneration Facility by any applicable CPUC order as well as any additional information that may be required of a Qualifying Cogeneration Facility in order to demonstrate compliance with all applicable California utility industry standards which have been adopted by the CPUC;

(l)

Provide copies of all daily Operating logs and Operating records to Buyer within 20 days of a Notice from Buyer;

(m)

Provide, upon Buyer’s request, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code or any Applicable Law mandating the reporting by investor-owned utilities of expected or experienced outages by facilities under contract to supply electric energy;

(n)

Pay all Scheduling Fees, as set forth in Exhibit G;

(o)

[Intentionally omitted]

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3.15

(p)

Register with the NERC as the Generating Facility’s Generator Owner and Generator Operator if Seller is required to register by the NERC;

(q)

Maintain documentation of all procedures applicable to the testing and maintenance of the Generating Facility protective devices as necessary to comply with the NERC Reliability Standards applicable to protection systems for electric generators if Seller is required to maintain such documentation by the NERC;

(r)

If Buyer is Scheduling Coordinator, then at least 30 days before the Term End Date, or in accordance with Section 7(a) of Exhibit G, or as soon as practicable before the date of an early termination of this Agreement, (i) submit to the CAISO the name of the Scheduling Coordinator that will replace Buyer, and (ii) cause the Scheduling Coordinator that will replace Buyer to submit a letter to the CAISO accepting the designation as Seller’s Scheduling Coordinator; and

(s)

If Buyer is not Scheduling Coordinator: (i)

Cause its Scheduling Coordinator to submit a Self-Schedule of Seller’s Day-Ahead Forecast associated with the Generating Facility through the IFM; Seller shall then submit the quantity associated with the SelfSchedule of Seller’s Day-Ahead Forecast as a Physical Trade to Buyer in the IFM, specifying the generating resource identifier and all other CAISO-required Inter-SC Trade attributes;

(ii)

Cause its Scheduling Coordinator to submit the IFM Day-Ahead Schedule quantity associated with the Generating Facility as an Inter-SC Trade of IFM Load Uplift Obligation to Buyer to be cleared through the Real-Time Market, specifying all CAISO-required Inter-SC Trade attributes; and

(iii)

Make available to Buyer all CAISO settlement data with respect to the Generating Facility required to validate payments made under this Agreement.

Power Product Curtailments at Transmission Provider’s or CAISO’s Request. (a)

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the CAISO, which may be communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when the CAISO orders curtailment and the Scheduling Coordinator implements such curtailment in compliance with the CAISO Tariff or applicable orders to avoid or address a declared System Emergency.

(b)

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the Transmission Provider, which may be

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communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when curtailment of the Power Product is required to comply with:

(c)

3.16

(i)

A CAISO curtailment declared pursuant to Section 3.15(a) or Transmission Provider declared Emergency Condition, subject to the interconnection agreement between Seller and the Transmission Provider; or

(ii)

Transmission Provider’s maintenance requirements, subject to the interconnection agreement between Seller and the Transmission Provider.

Notwithstanding the above, except as may be required in order to respond to any Emergency Condition or System Emergency, Buyer shall, consistent with FERC Order 888 and the interconnection agreement between Seller and the Transmission Provider and with the applicable provisions of the CAISO Tariff: (i)

Use reasonable good faith efforts to coordinate Transmission Provider’s curtailment needs with Seller to the extent it can influence such needs; or

(ii)

Request the Transmission Provider and CAISO limit the curtailment duration.

(d)

If Seller has entered into a QF PGA or PGA with the CAISO, or an interconnection agreement, the terms of the applicable QF PGA or PGA and the applicable interconnection agreement with respect to CAISO or Transmission Provider curtailments, shall govern the rights and obligations of Buyer and Seller to the extent any provision of this Section 3.15 is inconsistent with such applicable QF PGA or PGA, and interconnection agreement.

(e)

In the event Seller interconnects with a Person other than the CAISO, Seller shall adhere to any reliability curtailment order by such Person pursuant to the applicable tariff provisions of such Person.

Report of Lost Output. To the extent the conditions set forth in Sections 3.16(a) through (e) occur, Seller shall prepare and provide to Buyer, by the fifth Business Day following the end of each month during the Term, a lost output report. The lost output report shall identify the date, time, duration, cause and amount by which the Metered Energy was reduced below the Seller’s Energy Forecast due to: (a)

Maintenance Outages;

(b)

Major Overhauls;

(c)

CAISO or Transmission Provider-ordered curtailments;

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3.17

(d)

Force Majeure; or

(e)

Forced Outages.

FERC Qualifying Cogeneration Facility Status. (a)

Subject to Section 9.09, within 30 Business Days following the end of each year, and within 30 Business Days following the Term End Date, Seller shall provide to Buyer: (i)

A completed copy of Buyer’s “QF Efficiency Monitoring Program – Cogeneration Data Reporting Form”, substantially in the form of Exhibit T, with calculations and verifiable supporting data, which demonstrates the compliance of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation with qualifying cogeneration facility operating and efficiency standards set forth in 18 CFR Part 292, Section 292.205 “Criteria for Qualifying Cogeneration Facilities”, for the applicable year; or

(ii)

A copy of a FERC order waiving for the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation the applicable operating and efficiency standards for qualifying cogeneration facilities, as contemplated in 18 CFR Part 292, Section 292.205, “Criteria for Qualifying Cogeneration Facilities”, for the applicable year, if Seller has received such FERC order; provided, that in the event that Seller receives such a FERC order after the time periods set forth above, Seller shall satisfy this requirement by submitting such FERC order to Buyer within 5 Business Days after FERC’s issuance of such FERC order.

(b)

[Intentionally omitted.]

(c)

Seller shall take all necessary steps, including making or supporting timely filings with the FERC in order to maintain, or obtain a FERC waiver of, the Qualifying Cogeneration Facility status of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation throughout the Term; provided, however, that this obligation does not apply to the extent Seller is unable to maintain Qualifying Cogeneration Facility status using commercially reasonable efforts because of (i) a change in PURPA or in regulations of the FERC implementing PURPA occurring after the Effective Date, or (ii) a change in Applicable Laws directly impacting the Qualifying Cogeneration Facility status

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of the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation occurring after the Effective Date. The term “commercially reasonable efforts” in this Section 3.17(c) does not require Seller to pay or incur more than $20,000 multiplied by the number of Term Years in the Term. 3.18

3.19

Notice of Cessation or Termination of Service Agreements. Seller shall provide Notice to Buyer within one Business Day if there is a termination of, or cessation of service under, any agreement required in order for the Generating Facility to: (a)

Interconnect with the Transmission Provider’s electric system;

(b)

Transmit and deliver electric energy to the Delivery Point; or

(c)

Own and operate any CAISO-Approved Meter.

Buyer’s Access Rights. (a)

(b)

3.20

Upon providing at least one Business Day advance Notice to Seller, or as set forth in any Applicable Law (whichever is later), Buyer has the right to examine the Site, the Generating Facility and the Operating records, provided that Buyer follows Seller’s safety policies and procedures that Seller has communicated to Buyer, does not interfere with or hinder Seller’s Operations, and agrees to escorted access to the Generating Facility during regular business hours for: (i)

Any purpose reasonably connected with this Agreement;

(ii)

The exercise of any and all rights of Buyer under Applicable Law or its tariff schedules and rules on file with the CPUC; or

(iii)

The inspection and testing of any Check Meter, CAISO-Approved Meter or the Telemetry System.

Seller shall promptly provide Buyer access to all meter data and data acquisition services both in real-time, and at later times, as Buyer may reasonably request. Seller shall promptly inform Buyer of meter quantity changes after becoming aware of, or being informed of, any such changes by the CAISO. Seller shall provide instructions to the CAISO granting authorizations or other documentation sufficient to provide Buyer with access to the CAISO-Approved Meter and to Seller’s settlement data on OMAR.

Seller Financial Information.

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(a)

The Parties shall determine, through consultation and review with their respective independent registered public accounting firms, whether Buyer is required to consolidate Seller’s financial statements with Buyer’s financial statements for financial accounting purposes under Accounting Standards Codification (ASC) 810/Accounting Standards Update 2009-17, “Consolidation of Variable Interest Entities” (ASC 810), or future guidance issued by accounting profession governance bodies or the SEC that affects Buyer accounting treatment for this Agreement (the “Financial Consolidation Requirement”).

(b)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then: (i)

Within 20 days following the end of each year (for each year that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the year. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements. The annual financial statements should include quarter-to-date and yearly information. Buyer shall provide to Seller a checklist before the end of each year listing the items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the information on the checklist. If audited financial statements are prepared for Seller for the year, Seller shall provide such statements to Buyer within five Business Days after those statements are issued.

(ii)

Within 15 days following the end of each fiscal quarter (for each quarter that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the quarterly period. The financial statements should include quarter-to-date and year-to-date information. Buyer shall provide to Seller a checklist before the end of each quarter listing items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with

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true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements. (iii)

(c)

If Seller regularly prepares its financial data in accordance GAAP, the International Financial Reporting Standards (“IFRS”), or any successor to either of the foregoing (“Successor”), the financial information provided to Buyer shall be prepared in accordance with such principles. If Seller is not a SEC registrant and does not regularly prepare its financial data in accordance with GAAP, IFRS or Successor, the information provided to Buyer shall be prepared in a format consistent with Seller’s regularly applied accounting principles, e.g., the format that Seller uses to provide financial data to its auditor.

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then promptly upon Notice from Buyer, Seller shall allow Buyer’s independent registered public accounting firm such access to Seller’s records and personnel, as reasonably required so that Buyer’s independent registered public accounting firm can conduct financial statement audits in accordance with the standards of the Public Company Accounting Oversight Board (United States), as well as internal control audits in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, as applicable. All expenses for the foregoing shall be borne by Buyer. If Buyer’s independent registered public accounting firm during or as a result of the audits permitted in this Section 3.20(c) determines a material weakness or significant deficiency, as defined by GAAP, IFRS or Successor, as applicable, exists in Seller’s internal controls over financial reporting, then within 90 days of Seller’s receipt of Notice from Buyer, Seller shall remediate any such material weakness or significant deficiency; provided, however, that Seller has the right to challenge the appropriateness of any determination of material weakness or significant deficiency. Seller’s true up to actual activity for yearly or quarterly information as provided herein shall not be evidence of material weakness or significant deficiency.

(d)

Buyer shall treat Seller’s financial statements and other financial information provided under the terms of this Section 3.20 in strict confidence and, accordingly: (i)

Shall utilize such Seller financial information only for purposes of preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, for making regulatory, tax or other filings required by law in which Buyer is required to demonstrate or certify its or any parent company’s financial condition or to obtain credit ratings;

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3.21

(ii)

Shall make such Seller financial information available only to its officers, directors, employees or auditors who are responsible for preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, to the SEC and the Public Company Accounting Oversight Board (United States) in connection with any oversight of Buyer’s or any Buyer parent company financial statement and to those Persons who are entitled to receive confidential information as identified in Sections 9.09(a)(vi) and 9.09(a)(vii); and

(iii)

Buyer shall ensure that its internal auditors and independent registered public accounting firm (1) treat as confidential any information disclosed to them by Buyer pursuant to this Section 3.20, (2) use such information solely for purposes of conducting the audits described in this Section 3.20, and (3) disclose any information received only to personnel responsible for conducting the audits.

(e)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then, within two Business Days following the occurrence of any event affecting Seller which Seller understands, during the Term, would require Buyer to disclose such event in a Form 8-K filing with the SEC, Seller shall provide to Buyer a Notice describing such event in sufficient detail to permit Buyer to make a Form 8-K filing.

(f)

If, after consultation and review, the Parties do not agree on issues raised by Section 3.20(a), then such dispute shall be subject to review by another independent audit firm not associated with either Party’s respective independent registered public accounting firm, reasonably acceptable to both Parties. This third independent audit firm will render its recommendation on whether consolidation by Buyer is required. Based on this recommendation, Seller and Buyer shall mutually agree on how to resolve the dispute. If Seller fails to provide the data consistent with the mutually agreed upon resolution, Buyer may declare an Event of Default pursuant to Section 6.01. If Buyer’s independent audit firm, after the review by the third independent audit firm still determines that Buyer must consolidate, then Seller shall provide the financial information necessary to permit consolidation to Buyer; provided, however, that in addition to the protections in Section 3.20(d), such information shall be password protected and available only to those specific officers, directors, employees and auditors who are preparing and certifying the consolidated financial statements and not for any other purpose.

NERC Electric System Reliability Standards. During the Term, for purposes of complying with any NERC Reliability Standards applicable to the Generating Facility, Seller (or an agent of Seller as agreed to by Buyer in its reasonable discretion) must, if required by the NERC, register with the NERC as the Generator Operator and the

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Generator Owner for the Generating Facility and must perform all Generator Operator Obligations and Generator Owner Obligations except those Generator Operator Obligations that Buyer, in its capacity as Scheduling Coordinator (if Seller has elected to have Buyer serve as its Scheduling Coordinator), is required to perform under this Agreement or under the CAISO Tariff. Notwithstanding anything to the contrary set forth in this Section 3.21 and subject to the indemnity obligations set forth in Section 9.03(h), each Party acknowledges that such Party’s performance of the Generator Operator Obligations or Generator Owner Obligations may not satisfy the requirements for self-certification or compliance with the NERC Reliability Standards, and that it shall be the sole responsibility of each Party to implement the processes and procedures required by the NERC, the WECC, the CAISO, or a Governmental Authority in order to comply with the NERC Reliability Standards. If Buyer is Seller’s Scheduling Coordinator, Buyer as Scheduling Coordinator will reasonably cooperate with Seller to the extent necessary to enable Seller to comply and for Seller to demonstrate Seller’s compliance with the NERC Reliability Standards referenced above. Buyer’s cooperation will include providing to Seller, or such other Person as Seller designates in writing, information in Buyer’s possession that Buyer as Scheduling Coordinator has provided to the CAISO related to the Generating Facility or actions that Buyer has taken as Scheduling Coordinator related to Seller’s compliance with the NERC Reliability Standards referenced above (e.g., Seller’s notices and updates provided by Buyer to the CAISO via SLIC). Buyer may, in its reasonable discretion (depending upon the quantity of information requested by Seller and the timeframe established by Seller for compliance), comply with the requirement to provide information set forth in the previous sentence, by making such information available for inspection by Seller or by providing responsive summaries or excerpts of same, so long as the foregoing enables Seller to comply with the NERC Reliability Standards. In addition, Buyer may redact any information or data that is confidential to Buyer from materials or information to be supplied to Seller. 3.22

Allocation of Availability Incentive Payments and Non-Availability Charges. (a)

If Buyer is the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of Buyer and for Buyer’s account and any Non-Availability Charges will be the responsibility of Buyer and for Buyer’s account.

(b)

If Buyer is not the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of

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Seller and for Seller’s account and any Non-Availability Charges will be the responsibility of Seller and for Seller’s account. 3.23

Seller’s Reporting Requirements. (a)

Seller shall comply with the reporting requirements set forth in Section 3 of Exhibit S.

(b)

Seller shall deliver to Buyer, on or before the 10th Business Day following receipt of a Notice from Buyer, such information that Buyer is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Buyer otherwise requires in order to comply with the Settlement Agreement. *** End of Article Three ***

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ARTICLE FOUR.

BUYER’S OBLIGATIONS

4.01

Obligation to Pay. For Seller’s full compensation under this Agreement, during the Term, Buyer shall make a monthly payment (a “Monthly Contract Payment”) calculated in accordance with Exhibit D.

4.02

Payment Adjustments. (a)

Buyer shall adjust each Monthly Contract Payment to Seller to account for: (i)

Scheduling Fees owed by Seller to Buyer, as set forth in Exhibit G;

(ii)

Any SDD Adjustment, as set forth in Exhibit K;

(iii)

Any Forecast penalties owed by Seller to Buyer, as set forth in Exhibit I;

(iv)

Any CAISO Charges owed by Seller to Buyer, as set forth in Exhibit J;

(v)

Any Physical Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit L;

(vi)

Any SC Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit M;

(vii)

Any payment adjustments (including adjustments to CAISO Charges) provided for under this Agreement;

(viii) Any Governmental Charges owed by either Party to the other Party, as set forth in Section 8.02;

(b)

(ix)

The agreement of the Parties that Buyer shall have no liability to make any energy payments to Seller for any electricity deliveries from the Generating Facility in a Term Year that exceed 120% of Expected Term Year Energy Production; and

(x)

Any payment adjustments provided for to determine Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges, as set forth in Exhibit S.

Unless otherwise required in Exhibit S, during the Term, any payment adjustments will be added to or deducted from a subsequent regular Monthly Contract Payment that is made by Buyer to Seller after the expiration of a 30-day

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period which begins upon Buyer’s receipt of all of the information required in order to calculate payment adjustments. (c)

4.03

Unless otherwise required in Exhibit S, after the Term End Date, Buyer shall invoice Seller for all payment adjustments within 60 days of Buyer’s receipt of all of the information required in order to calculate payment adjustments.

Payment Statement and Payment. (a)

No later than 30 days after the end of each calendar month (or the last day of the month if the month in which the payment statement is being sent is February), or the last Business Day of the month if such 30th day (or 28th or 29th day for February) is not a Business Day, Buyer shall mail to Seller: (i)

A table showing the hourly electric energy quantities for each of the following, in MWh per hour:

1)

Seller’s Energy Forecast;

2)

Seller’s Day-Ahead Forecast;

3)

Metered Energy;

4)

Metered Amounts;

5)

The final Buyer Energy Schedule; and

6)

The final Buyer Parent Energy Schedule.

(ii)

A statement showing:

1)

TOD Period subtotals and overall monthly totals for each of the items set forth in Section 4.03(a)(i);

2)

A calculation of the Monthly Contract Payment, as set forth in Exhibit D;

3)

A calculation of any payment adjustments pursuant to Section 4.02;

4)

A calculation of any payment adjustments pursuant to Exhibit S; and

5)

A calculation of the net dollar amount due for the month.

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(iii)

(b)

Buyer’s payment to Seller, in accordance with Section 9.15, in the net dollar amount owed to Seller for the month (less any overpayments by Buyer of Seller’s GHG Compliance Costs or GHG Charges under Section 4.04 in any calendar month); provided, however, in the event the statement shows a net amount owed to Buyer, Seller shall pay such amount within 20 days of the statement date or, if Seller fails to make such payment, Buyer may offset this amount from a subsequent Monthly Contract Payment.

If Buyer determines that a calculation of Metered Energy or Metered Amounts is incorrect as a result of an inaccurate meter reading or the correction of data by the CAISO in the CAISO’s meter-data acquisition and processing system, Buyer shall promptly recompute the Metered Energy or Metered Amounts quantity for the period of the inaccuracy based on an adjustment of such inaccurate meter reading in accordance with the CAISO Tariff. Buyer shall then promptly recompute any payment or payment adjustment affected by such inaccuracy. Any amount due from Buyer to Seller or Seller to Buyer, as the case may be, shall be made as an adjustment to the next monthly statement that is calculated after Buyer’s recomputation using corrected measurements. If the recomputation results in a net amount owed to Buyer after offsetting any amounts owing to Seller as shown on the next monthly statement, any such additional amount still owing to Buyer shall be shown as an adjustment on Seller’s monthly statement until such amount is fully collected by Buyer. At Buyer’s sole discretion, Buyer may offset any remaining amount owed to Buyer in any subsequent monthly payments to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice.

(c)

(d)

Buyer reserves the right to deduct amounts that would otherwise be due to Seller under this Agreement from any amounts owing and unpaid by Seller to Buyer: (i)

Under this Agreement; or

(ii)

Arising out of or related to any other agreement, tariff, obligation or liability pertaining to the Generating Facility.

Except as provided in Section 4.03(b) and as otherwise provided in this Section 4.03(d), if, within 45 days of receipt of Buyer’s payment statement, Seller does not give Notice to Buyer of an error, then Seller shall be deemed to have waived any error in Buyer’s statement, computation and payment and the statement shall

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be conclusively deemed correct and complete; provided, however, that if an error is identified by Seller as a result of settlement, audit or other information provided to Seller by the CAISO after the expiration of the original 45-day period, Seller shall have an additional 90 days from the date on which it receives the information from the CAISO in which to give Notice to Buyer of the error identified by such settlement, audit or other information. If Seller identifies an error in Seller’s favor and Buyer agrees that the identified error occurred, Buyer shall reimburse Seller for the amount of the underpayment caused by the error and add the underpayment to the next monthly statement that is calculated. If Seller identifies an error in Buyer’s favor and Buyer agrees that the identified error occurred, Seller shall reimburse Buyer for the amount of overpayment caused by the error and Buyer shall apply the overpayment to the next monthly statement that is calculated. If the recomputation results in a net amount still owing to Buyer after applying the overpayment, the next monthly statement shall show a net amount owing to Buyer. At Buyer’s sole discretion, Buyer may apply this net amount owing to Buyer in any subsequent monthly statements to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice. The Parties shall negotiate to resolve any disputes regarding claimed errors in a statement. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. Nothing in this Section 4.03 limits a Party’s rights under applicable tariffs, other agreements or Applicable Law.

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4.04

GHG Compliance Costs. Buyer shall pay for Seller’s GHG Compliance Costs and GHG Charges in accordance with Exhibit S; provided, however, that notwithstanding anything to the contrary set forth in this Agreement (including Exhibit S), in no event will Buyer pay for any of Seller’s GHG Compliance Costs or GHG Charges to the extent that such GHG Compliance Costs or GHG Charges are associated with deliveries of the Power Product that are in excess of 120% of the Expected Term Year Net Energy Production in any Term Year.

4.05

No Representation by Buyer. Any review by Buyer of the design, engineering, construction, testing and Operation of the Generating Facility is solely for Buyer’s information. Buyer makes no representation that: (a)

It has reviewed the financial viability, technical feasibility, operational capability, or long term reliability of the Generating Facility;

(b)

The Generating Facility complies with any Applicable Laws; or

(c)

The Generating Facility will be able to meet the terms of this Agreement.

Seller shall in no way represent to any third party that any such review by Buyer constitutes any such representation. 4.06

Buyer’s Responsibility. Buyer shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable transmission and delivery of electric energy at and after the Delivery Point.

4.07

Buyer’s Reporting Requirements. Buyer shall deliver to Seller, on or before the 10th Business Day following receipt of a Notice from Seller, such information as Seller is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Seller otherwise requires in order to comply with the Settlement Agreement. *** End of Article Four ***

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ARTICLE FIVE.

FORCE MAJEURE

5.01

No Default for Force Majeure. Neither Party will be in default in the performance of any of its obligations set forth in this Agreement, except for obligations to pay money, when and to the extent failure of performance is caused by Force Majeure.

5.02

Requirements Applicable to the Claiming Party. If a Party, because of Force Majeure, is rendered wholly or partly unable to perform its obligations when due under this Agreement, such Party (the “Claiming Party”) shall be excused from whatever performance is affected by the Force Majeure to the extent so affected. In order to be excused from its performance obligations under this Agreement by reason of Force Majeure: (a)

The Claiming Party, within 14 days after the initial occurrence of the claimed Force Majeure, must give the other Party Notice describing the particulars of the occurrence; and

(b)

The Claiming Party must provide timely evidence reasonably sufficient to establish that the occurrence constitutes Force Majeure as defined in this Agreement.

The suspension of the Claiming Party’s performance due to Force Majeure may not be greater in scope or longer in duration than is required by such Force Majeure. In addition, the Claiming Party shall use diligent efforts to remedy its inability to perform. This Article Five will not require the settlement of any strike, walkout, lockout or other labor dispute on terms which, in the sole judgment of the Claiming Party, are contrary to its interest. It is understood and agreed that the settlement of strikes, walkouts, lockouts or other labor disputes shall be at the sole discretion of the Claiming Party. When the Claiming Party is able to resume performance of its obligations under this Agreement, the Claiming Party shall give the other Party prompt Notice to that effect. 5.03

Termination. Either Party may terminate this Agreement on Notice, which Notice will be effective five Business Days after such Notice is provided, in the event of Force Majeure which materially interferes with such Party’s ability to perform its obligations under this Agreement and which extends for more than 365 consecutive days, or for more than a total of 365 days in any consecutive 540-day period. *** End of Article Five ***

Article Five

Force Majeure

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ARTICLE SIX. 6.01

EVENTS OF DEFAULT; REMEDIES

Events of Default. An “Event of Default” means the occurrence of any of the following : (a)

With respect to either Party (a “Defaulting Party”): (i)

Any representation or warranty made by such Party in this Agreement is false or misleading in any material respect when made or when deemed made or repeated if the representation or warranty is continuing in nature, if such misrepresentation or breach of warranty is not: 1)

Remedied within 10 Business Days after Notice from the NonDefaulting Party to the Defaulting Party; or

2)

Capable of a cure, but the Non-Defaulting Party’s damages resulting from such misrepresentation or breach of warranty can reasonably be ascertained and the payment of such damages is not made within 10 Business Days after a Notice of such damages is provided by the Non-Defaulting Party to the Defaulting Party;

(ii)

Except for an obligation to make payment when due, the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default or to the extent excused by a Force Majeure) if such failure is not remedied within 30 days after Notice of such failure is provided by the Non-Defaulting Party to the Defaulting Party, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 30-day cure period, the Defaulting Party shall have such additional time (not to exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as such Defaulting Party promptly commences and diligently pursues such cure;

(iii)

A Party fails to make when due any payment (other than amounts disputed in accordance with the terms of this Agreement) due and owing under this Agreement and such failure is not cured within five Business Days after Notice is provided by the Non-Defaulting Party to the Defaulting Party of such failure;

(iv)

A Party becomes Bankrupt;

(v)

A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another Person and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee Person fails to assume all the obligations of such

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Party under this Agreement to which such Party or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party; (vi)

An event of default occurs (howsoever determined) under any agreement between Buyer and Seller (other than this Agreement but including the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation) and, after giving effect to any applicable notice requirement or cure period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that agreement; or

(vii)

The Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, the Transition EEI Agreement or the Transition Tolling Confirmation or Transition RA Confirmation.

(b)

[Intentionally omitted.]

(c)

With respect to Seller: (i)

Seller does not own or lease the Generating Facility or otherwise have the authority over the Generating Facility as required in Section 3.03, and Seller has not cured a failure with respect to Section 3.03 within 30 days after providing Notice to Buyer in accordance with Section 3.03;

(ii)

If Seller abandons the Generating Facility (for purposes of this Section 6.01(c)(ii), Seller will be deemed to have abandoned the Generating Facility if Seller has ceased work on the Generating Facility or the Generating Facility has ceased production and delivery of the Product for a consecutive thirty (30) day period and such cessation is not a result of an event of Force Majeure);

(iii)

During the Term, except as provided for in Section 3.01(d), Seller (1) conveys, transfers, allocates, designates, awards, reports or otherwise provides any and all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except as may relate to transactions in the imbalance market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) starts up or Operates the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws);

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(iv)

Seller intentionally or knowingly delivers, Schedules, or attempts to deliver or Schedule at the Delivery Point for sale under this Agreement electric energy that was not generated by the Generating Facility;

(v)

Seller removes from the Site equipment upon which the Net Contract Capacity has been based, except for the purposes of replacement, refurbishment, repair, repowering or maintenance, and such equipment is not returned within five Business Days after Notice from Buyer to Seller;

(vi)

Subject to Section 3.17(c), the Generating Facility fails to maintain its status as a Qualifying Cogeneration Facility;

(vii)

Termination of, or cessation of service under, any agreement necessary for the interconnection of the Generating Facility to the Transmission Provider’s electric system for transmission and delivery of the electric energy from the Generating Facility to the Delivery Point, or for metering the Metered Energy, and such service is not reinstated, or alternative arrangements implemented, within 120 days after such termination or cessation;

(viii) Seller fails to make all reasonable efforts to increase the Power Output from the Generating Facility to the Firm Contract Capacity during an Emergency Condition or a System Emergency; (ix)

Seller fails to provide any financial statements or other information within the timeframe and in the manner set forth in Sections 3.20(b)(i) and (ii), and such failure is not remedied within 10 days after Notice from Buyer to Seller;

(x)

Seller fails to remediate any material weakness or significant deficiency in internal controls over financial reporting in accordance with Section 3.20(c), and such failure is not remedied within 90 days after Notice from Buyer to Seller;

(xi)

Seller fails to take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term as specified in Section 3.01, if such failure is not remedied within 10 days after Notice of such failure is provided by Buyer to Seller, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 10-day cure period, Seller shall have such additional time (not to exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as Seller promptly commences and diligently pursues such cure;

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(xii)

[Intentionally omitted]

(xiii) If any failure by Seller to comply with the CAISO Tariff materially impacts Buyer’s ability to comply with this Agreement, the CAISO Tariff or other Applicable Laws, and such failure by Seller (including any consequences suffered by Buyer) is not cured within 30 days after Notice from Buyer to Seller;

6.02

6.03

(xiv)

If Seller materially modifies or repowers the Generating Facility (except as provided in Section 3.07(c)) without Buyer’s prior written consent; or

(xv)

If Seller fails to satisfy all of the conditions set forth in Section 2.01 before the Term Start Date, and such failure is not cured within 30 Business Days after Notice from Buyer to Seller.

Early Termination. If an Event of Default has occurred, there will be no opportunity for cure except as specified in Section 6.01 or pursuant to a Collateral Assignment Agreement agreed upon by Buyer, Seller and Lender in accordance with Section 9.05. The Party taking the default (the “Non-Defaulting Party”) will have the right to: (a)

Designate by Notice to the Defaulting Party a date, no later than 20 days after the Notice is effective, for the early termination of this Agreement (an “Early Termination Date”);

(b)

Immediately suspend performance under this Agreement; and

(c)

Pursue all remedies available at law or in equity against the Defaulting Party (including monetary damages), except to the extent that such remedies are limited by the terms of this Agreement.

Termination Payment. As soon as practicable after an Early Termination Date is declared, the Non-Defaulting Party shall provide Notice to the Defaulting Party of the sum of all amounts owed by the Defaulting Party under this Agreement less any amounts owed by the Non-Defaulting Party to the Defaulting Party under this Agreement, including any Forward Settlement Amount (the “Termination Payment”). The Notice shall include a written statement setting forth, in reasonable detail, the calculation of such Termination Payment, including the Forward Settlement Amount, together with appropriate supporting documentation. If the Termination Payment is positive, the Defaulting Party shall pay such amount to the Non-Defaulting Party within 10 Business Days after the Notice is provided. If the Termination Payment is negative (i.e., the Non-Defaulting Party owes the Defaulting Party more than the Defaulting Party owes the Non-Defaulting Party), then the Non-

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Events of Default; Remedies

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Defaulting Party shall pay such amount to the Defaulting Party within 10 Business Days after the Notice is provided. The Parties shall negotiate to resolve any disputes regarding the calculation of the Termination Payment and Forward Settlement Amount. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. *** End of Article Six ***

Article Six

Events of Default; Remedies

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ARTICLE SEVEN. LIMITATIONS OF LIABILITIES EXCEPT AS SET FORTH IN THIS ARTICLE SEVEN, THERE ARE NO WARRANTIES BY EITHER PARTY UNDER THIS AGREEMENT, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY IS LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED, UNLESS THE PROVISION IN QUESTION PROVIDES THAT THE EXPRESS REMEDIES ARE IN ADDITION TO OTHER REMEDIES THAT MAY BE AVAILABLE. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, THE OBLIGOR’S LIABILITY IS LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. THE VALUE OF ANY PRODUCTION TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. THE VALUE OF ANY INVESTMENT TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. UNLESS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, INCLUDING THE PROVISIONS OF SECTION 9.03, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS IMPOSED IN THIS ARTICLE SEVEN ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE.

Article Seven

Limitations of Liabilities

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Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID UNDER THIS AGREEMENT ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED UNDER THIS AGREEMENT CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. NOTHING IN THIS ARTICLE SEVEN PREVENTS, OR IS INTENDED TO PREVENT BUYER FROM PROCEEDING AGAINST OR EXERCISING ITS RIGHTS WITH RESPECT TO ANY SECURED INTEREST IN COLLATERAL. *** End of Article Seven ***

Article Seven

Limitations of Liabilities

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ARTICLE EIGHT. GOVERNMENTAL CHARGES 8.01

Cooperation to Minimize Tax Liabilities. Each Party shall use diligent efforts to implement the provisions of and to administer this Agreement in accordance with the intent of the Parties to minimize all taxes, so long as neither Party is materially adversely affected by such efforts.

8.02

Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any Governmental Authority (“Governmental Charges”) on or with respect to the Generating Facility, Monthly Contract Payments made by Buyer to Seller, or the Power Product before the Delivery Point, including ad valorem taxes and other taxes attributable to the Generating Facility, the Site or land rights or interests in the Site or the Generating Facility. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Power Product at and after the Delivery Point. If Seller is required by Applicable Laws to remit or pay Governmental Charges which are Buyer’s responsibility under this Agreement, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by Applicable Law or regulation to remit or pay Governmental Charges which are Seller’s responsibility under this Agreement, Buyer may deduct such amounts from payments to Seller made pursuant to Article Four. If Buyer elects not to deduct such amounts from Seller’s payments, Seller shall promptly reimburse Buyer for such amounts upon Notice from Buyer of the amount to be reimbursed. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under Applicable Laws. Nothing stated in this Section 8.02 relieves Buyer of its obligation to pay Seller for Seller’s GHG Compliance Costs and GHG Charges in accordance with and subject to this Agreement (including Exhibit S).

8.03

Providing Information to Taxing Governmental Authorities. To the extent required by Applicable Law and subject to Section 9.09(b), each Party shall provide information concerning the Generating Facility to any requesting taxing Governmental Authority. *** End of Article Eight ***

Article Eight

Governmental Charges

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Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

ARTICLE NINE. 9.01

MISCELLANEOUS

Representations, Warranties and Covenants. (a)

On the Effective Date, each Party represents and warrants to the other Party that: (i)

It is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;

(ii)

The execution, delivery and performance of this Agreement are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any Applicable Laws;

(iii)

This Agreement constitutes a legally valid and binding obligation enforceable against it in accordance with its terms, subject to any Equitable Defenses;

(iv)

There is not pending, or to its knowledge, threatened against it or, in the case of Seller, any of its Related Entities, any legal proceeding that could materially adversely affect its ability to perform under this Agreement;

(v)

No Event of Default with respect to it has occurred and is continuing and no such event or circumstance will occur as a result of its entering into or performing its obligations under this Agreement;

(vi)

It is acting for its own account, and its decision to enter into this Agreement is based upon its own judgment, not in reliance upon the advice or recommendations of the other Party and it is capable of assessing the merits of and understanding, and understands and accepts the terms, conditions and risks of this Agreement;

(vii)

It has not relied on any promises, representations, statements or information of any kind whatsoever that are not contained in this Agreement in deciding to enter into this Agreement; and

(viii) It has entered into this Agreement in connection with the conduct of its business and it has the capacity or ability to provide or receive the Power Product as contemplated by this Agreement. (b)

On the Effective Date, each Party covenants to the other Party that, except for CPUC Approval in the case of Buyer, and for certain authorizations that Seller

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Miscellaneous

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Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

will need to obtain from FERC, it has or will timely acquire all regulatory authorizations necessary for it to legally perform its obligations under this Agreement. (c) 9.02

9.03

On the Effective Date, Seller represents and warrants to Buyer that the Generating Facility is an Existing Qualifying Cogeneration Facility.

Additional Covenants by Seller. Seller covenants to Buyer that: (a)

It will have Site Control as of the earlier of (i) the Term Start Date and (ii) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term;

(b)

Throughout the Term, it or its subcontractors will own or lease and Operate the Generating Facility unless otherwise agreed to by the Parties;

(c)

Throughout the Term, it will deliver the Product to Buyer free and clear of all liens, security interests, Claims and encumbrances or any interest therein or thereto by any Person;

(d)

Throughout the Term, it will hold the rights to all of the Product, subject to the terms of this Agreement;

(e)

From the Effective Date until the Term End Date, the Generating Facility will maintain its status as a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(f)

Throughout the Term, it will not (1) convey, transfer, allocate, designate, award, report or otherwise provide any or all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except, if Buyer is not Scheduling Coordinator, as may relate to transactions in the Real-Time Market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) start-up or Operate the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws); and

(g)

Seller shall comply with all (i) applicable cap-and-trade programs for the regulation of Greenhouse Gas, as established by any Governmental Authority pursuant to federal or state legislation, and (ii) other applicable programs regulating Greenhouse Gas emissions.

Indemnity.

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Miscellaneous

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(a)

Each Party as indemnitor shall defend, save harmless and indemnify the other Party and the directors, officers, employees, and agents of such other Party against and from any and all loss, liability, damage, claim, cost, charge, demand, or expense (including any direct, indirect, or consequential loss, liability, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees) for injury or death to Persons, including employees of either Party, and physical damage to property including property of either Party arising out of or in connection with the negligence or willful misconduct of the indemnitor relating to its obligations under this Agreement. This indemnity applies notwithstanding the active or passive negligence of the indemnitee. However, neither Party is indemnified under this Agreement for its loss, liability, damage, claim, cost, charge, demand or expense to the extent resulting from its negligence or willful misconduct.

(b)

Each Party releases and shall defend, save harmless and indemnify the other Party from any and all loss, liability, damage, claim, cost, charge, demand or expense arising out of or in connection with any breach made by the indemnifying Party of its representations, warranties and covenants in Section 9.01 and Section 9.02.

(c)

The provisions of this Section 9.03 may not be construed to relieve any insurer of its obligations to pay any insurance Claims in accordance with the provisions of any valid insurance policy.

(d)

Notwithstanding anything to the contrary in this Agreement, if Seller fails to comply with the provisions of Section 9.10, Seller shall, at its own cost, defend, save harmless and indemnify Buyer, its directors, officers, employees, and agents, assigns, and successors in interest, from and against any and all loss, liability, damage, claim, cost, charge, demand, or expense of any kind or nature (including any direct, indirect, or consequential loss, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees and other costs of litigation), resulting from injury or death to any person or damage to any property, including the personnel or property of Buyer, to the extent that Buyer would have been protected had Seller complied with all of the provisions of Section 9.10. The inclusion of this Section 9.03(d) is not intended to create any express or implied right in Seller to elect not to provide the insurance required under Section 9.10.

(e)

Each Party shall defend, save harmless and indemnify the other Party against any Governmental Charges for which such indemnifying Party is responsible under Article Eight.

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Miscellaneous

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9.04

(f)

Seller shall defend, save harmless and indemnify Buyer against any increase in GHG Compliance Costs and other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating Facility to the extent that such GHG Compliance Costs or other costs result from Seller’s modification or repowering of the Generating Facility in accordance with Section 3.07.

(g)

Seller shall defend, save harmless and indemnify Buyer against any penalty imposed upon Buyer as a result of Seller’s failure to fulfill its obligations regarding Resource Adequacy Benefits as set forth in Sections 3.01 and 3.02, with the exception of the obligations set forth in Section 3.01(c)(vi).

(h)

Seller is solely responsible for any NERC Standards Non-Compliance Penalties arising from or relating to Seller’s failure to perform the Generator Operator Obligations or the Generator Owner Obligations for which Seller is responsible, in accordance with Section 3.21, and will indemnify, defend and hold Buyer harmless from and against all liabilities, damages, Claims, losses, and reasonable costs and expenses (which shall include reasonable costs and expenses of outside or in-house counsel) incurred by Buyer arising from or relating to Seller’s actions or inactions that result in NERC Standards Non-Compliance Penalties or an attempt by any Governmental Authority, Person to assess such NERC Standards Non-Compliance Penalties against Buyer. Buyer will indemnify, defend and hold Seller harmless from and against all liabilities, damages, Claims, losses and reasonable costs and expenses (which shall include reasonable costs of outside and in-house counsel) incurred by Seller for any NERC Standards NonCompliance Penalties to the extent they are due to Buyer’s negligence or willful misconduct in performing its role as Seller’s Scheduling Coordinator during the Term.

(i)

All indemnity rights will survive the termination of this Agreement for 12 months.

Assignment. (a)

With Consent. Subject to Section 9.04(b), Seller may not transfer or assign this Agreement or its rights under this Agreement without the prior written consent of Buyer, which consent may not be unreasonably withheld or delayed. Any direct or indirect change of control of Seller (whether voluntary or by operation of law) will be deemed an assignment and will require the prior written consent of Buyer, which consent will not be unreasonably withheld. For purposes of this Section 9.04, Buyer will not withhold its consent to an indirect change of control of Seller if Seller demonstrates to Buyer’s reasonable satisfaction that Seller shall continue to perform its obligations under this Agreement as if no such indirect change of control had occurred.

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Miscellaneous

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(b)

9.05

Without Consent. Notwithstanding anything to the contrary set forth in Section 9.04(a): (i)

Seller may, without the consent of Buyer (and without relieving itself from liability hereunder): (1) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements in accordance with Section 9.05; or (2) transfer or assign this Agreement to a Related Entity of Seller, which Related Entity’s creditworthiness is equal to or higher than that of Seller; and

(ii)

Seller does not need to obtain Buyer’s consent to any change of control described in this Section 9.04 if such change of control results from a purchase of the outstanding shares of a publicly traded company.

Consent to Collateral Assignment. Subject to the provisions of this Section 9.05, Seller may (but is not obligated to) assign this Agreement as collateral to a Lender for any financing or refinancing of the Generating Facility, including a Sale-Leaseback Transaction or Equity Investment and, in connection therewith, Buyer shall in good faith work with Seller and Lender to agree upon a consent to a collateral assignment of this Agreement or to a Sale-Leaseback Transaction or Equity Investment, as applicable (“Collateral Assignment Agreement”). The Collateral Assignment Agreement shall be in form and substance reasonably agreed to by Buyer, Seller and Lender, and shall include, among others, the following provisions (together with such other commercially reasonable provisions required by any Lender that are reasonably acceptable to Buyer): (a)

Buyer shall give, to the Person(s) to be specified by Lender in the Collateral Assignment Agreement, simultaneously with the Notice to Seller and before exercising its right to terminate this Agreement, written Notice of any event or circumstance known to Buyer which would, if not cured within the applicable cure period specified in Article VI, constitute an Event of Default (an “Incipient Event of Default”);

(b)

Lender shall have the right to cure an Incipient Event of Default or an Event of Default by Seller in accordance with the same provisions of this Agreement as apply to Seller;

(c)

Following an Event of Default by Seller under this Agreement, Buyer may require Seller to (although Lender may, but shall have no obligation, subject to 9.05(g)) provide to Buyer a report concerning:

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Miscellaneous

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(i)

The status of efforts by Seller or Lender to develop a plan to cure the Event of Default;

(ii)

Impediments to the cure plan or its development;

(iii)

If a cure plan has been adopted, the status of the cure plan’s implementation (including any modifications to the plan as well as the expected timeframe within which any cure is expected to be implemented); and

(iv)

Any other information which Buyer may reasonably require related to the development, implementation and timetable of the cure plan;

(d)

Seller or Lender shall provide the report to Buyer within 10 Business Days after Notice from Buyer requesting the report. Buyer shall have no further right to require the report with respect to a particular Event of Default after that Event of Default has been cured;

(e)

Lender shall have the right to cure an Event of Default or Incipient Event of Default on behalf of Seller, only if Lender sends a written notice to Buyer before the end of any cure period indicating Lender’s intention to cure. Lender may remedy or cure the Event of Default or Incipient Event of Default within the cure period under this Agreement. Such cure period for Lender shall be extended for each day Buyer does not provide the Notice to Lender referred to in Section 9.05(a). In addition, such cure period may, in Buyer’s reasonable discretion, be extended by no more than an additional 180 days. If possession of the Generating Facility is necessary to cure such Incipient Event of Default or Event of Default, Lender has commenced foreclosure proceedings within 60 days after receipt of such Notice from Buyer, and Lender is making diligent and consistent efforts to complete such foreclosure, take possession of the Generating Facility and promptly cure the Incipient Event of Default or Event of Default, Lender or its designee(s) or assignee(s) will be allowed a reasonable period of time to complete such foreclosure proceedings, take possession of the Generating Facility and cure such Incipient Event of Default or Event of Default, not to exceed 180 days after Lender’s commencement of foreclosure. Additionally, if Lender is prohibited from curing any Incipient Event of Default or Event of Default by any process, stay or injunction issued by a Governmental Authority or pursuant to any bankruptcy, insolvency or similar proceedings, then the time period for curing such Incipient Event of Default or Event of Default shall be extended for the period of the prohibition provided that Lender is exercising reasonable diligence in having such process, stay or injunction removed;

(f)

Lender shall have the right to consent before any termination of this Agreement which does not arise out of an Event of Default or the end of the Term;

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(g)

Lender shall receive prior Notice of, and shall have the right to approve material amendments to this Agreement, which approval may not be unreasonably withheld, delayed or conditioned;

(h)

In the event Lender, directly or indirectly, takes title to the Generating Facility (including title by foreclosure or deed in lieu of foreclosure), the Person taking title to the Generating Facility shall assume all of Seller’s obligations arising under this Agreement and all related agreements (subject to such limits on liability as are mutually agreed to by Seller, Buyer and Lender as set forth in the Collateral Assignment Agreement); provided, however, that Lender (or such Person) shall have no liability for any monetary obligations of Seller under this Agreement which are due and owing to Buyer as of the assumption date (but this provision may not be interpreted to limit Buyer’s rights to proceed against Seller as a result of an Event of Default) and Lender’s (or such Person’s) liability to Buyer after such assumption shall be limited to its interest in the Generating Facility; provided further, that before such assumption, if Buyer advises Lender (or such Person) that Buyer will require that Lender (or such Person) cure (or cause to be cured) one or more monetary or non-monetary Incipient Event(s) of Default or Event(s) of Default existing as of the date such Person takes title in order to avoid the exercise by Buyer (in its sole discretion) of Buyer’s right to terminate this Agreement with respect to such Incipient Event(s) of Default or Event(s) of Default, then Lender (or such Person) at its option and in its sole discretion may elect to either (i) cause such Incipient Event(s) of Default or Event of Default to be cured, or (ii) not assume this Agreement;

(i)

If Lender has assumed this Agreement as provided in Section 9.05(h) and elects to sell or transfer the Generating Facility (after Lender directly or indirectly, takes title to the Generating Facility), or sale of the Generating Facility occurs through the actions of Lender or an agent of or representative of Lender (excluding any foreclosure sale where a third party other than Lender, Seller, an Related Entity of Lender or an Related Entity of Seller is the buyer), then Lender must cause the transferee or buyer to assume all of Seller’s obligations arising under this Agreement and all related agreements as a condition of the sale or transfer excluding, however, a foreclosure (unless the transferee or buyer is Lender, Seller, an Related Entity of Lender or an Related Entity of Seller). Lender shall be released from all further obligations under the Agreement and all related documents following such assumption. Such sale or transfer (excluding a foreclosure) may be made only to a Person reasonably acceptable to Buyer; and

(j)

If this Agreement is rejected in Seller’s Bankruptcy or otherwise terminated in connection therewith and if Lender or its representative or designee, directly or indirectly, takes title to the Generating Facility, then, at the request of either Buyer or Lender, Buyer and Lender (or its designee or representative) shall promptly enter into a new agreement with Buyer having substantially the same

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terms as this Agreement for the term that would have been remaining under this Agreement, provided that Lender’s (or its designee’s or representative’s) liability under such new agreement shall be limited to its interest in the Generating Facility and neither Lender (or its designee or representative) nor Buyer shall have any personal liability to the other for any amounts owing and neither Buyer nor Lender (or its designee or representative) shall have any obligation to cure any defaults under the original Agreement that was rejected in, or otherwise terminated in connection with Seller’s Bankruptcy. 9.06

Governing Law and Jury Trial Waiver. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER ARE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. TO THE EXTENT ENFORCEABLE AT SUCH TIME, EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT.

9.07

Notices. All Notices shall be provided as specified in Exhibit N. Notices (other than Forecasts and Scheduling requests) shall, unless otherwise specified in this Agreement, be in writing and may be delivered by hand delivery, first class United States mail, overnight courier service, electronic transmission or facsimile. Notices provided in accordance with this Section 9.07 are deemed given as follows: (a)

Notice by facsimile, electronic transmission or hand delivery is deemed given at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise are deemed given at the close of business on the next Business Day;

(b)

Notice by overnight first class United States mail or overnight courier service is deemed given on the next Business Day after such Notice is sent out;

(c)

Notice by first class United States mail is deemed given two Business Days after the postmarked date;

(d)

Notices are effective on the date deemed given, unless a different date for the Notice to go into effect is stated in another section of this Agreement;

(e)

A Party may change its designated representatives, addresses and other contact information by providing Notice of same in accordance herewith; and

(f)

All Notices for this Generating Facility must reference the identification number set forth on the cover page of this Agreement.

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9.08

General. (a)

This Agreement supersedes all prior agreements, whether written or oral, between the Parties with respect to its subject matter and constitutes the entire agreement between the Parties relating to its subject matter.

(b)

This Agreement will not be construed against any Party as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof.

(c)

Except to the extent provided for in this Agreement, no amendment or modification to this Agreement is enforceable unless reduced to a writing signed by all Parties.

(d)

If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement will remain in full force and effect. Any provision of this Agreement held invalid or unenforceable only in part or degree will remain in full force and effect to the extent not held invalid or unenforceable.

(e)

Waiver by a Party of any default by the other Party will not be construed as a waiver of any other default.

(f)

The term “including” when used in this Agreement is by way of example only and will not be considered in any way to be in limitation.

(g)

The word “or” when used in this Agreement includes the meaning “and/or” unless the context unambiguously dictates otherwise.

(h)

The headings used in this Agreement are for convenience and reference purposes only and will not affect its construction or interpretation. All references to “Articles”, “Sections” and “Exhibits” refer to the corresponding Articles, Sections and Exhibits of this Agreement. Unless otherwise specified, all references to “Articles” or “Sections” in Exhibits A through T refer to the corresponding Articles and Sections in the main body of this Agreement. Words having wellknown technical or industry meanings have such meanings unless otherwise specifically defined in this Agreement.

(i)

Where days are not specifically designated as Business Days, they are calendar days. Where years are not specifically designated as Term Years, they are calendar years.

(j)

This Agreement will apply to, be binding in all respects upon and inure to the benefit of the successors and permitted assigns of the Parties. Nothing in this

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Agreement will be construed to give any Person other than the Parties any legal or equitable right, remedy or claim under or with respect to this Agreement or any provision of this Agreement, except as shall inure to a successor or permitted assignee.

9.09

(k)

No provision of this Agreement is intended to contradict or supersede any applicable agreement between the Parties or between or among Seller, the CAISO and the Transmission Provider, covering transmission, distribution, metering, scheduling or interconnection of electric energy (including the PGA and QF PGA). In the event of an apparent contradiction between this Agreement and any such agreement, the applicable agreement controls.

(l)

Whenever this Agreement specifically refers to any law, tariff, government department or agency, regional reliability council, Transmission Provider, or credit rating agency, the Parties agree that the reference also refers to any successor to such law, tariff or organization.

(m)

The Parties acknowledge and agree that this Agreement and the transactions contemplated by this Agreement constitute a “forward contract” within the meaning of the United States Bankruptcy Code and that Buyer and Seller are each “forward contract merchants” within the meaning of the United States Bankruptcy Code.

(n)

This Agreement may be executed in one or more counterparts, each of which will be deemed to be an original of this Agreement and all of which, when taken together, will be deemed to constitute one and the same agreement. The exchange of copies of this Agreement and of signature pages by facsimile transmission, an Adobe Acrobat file or by other electronic means constitutes effective execution and delivery of this Agreement as to the Parties and may be used in lieu of the original Agreement for all purposes. Signatures of the Parties transmitted by facsimile or by other electronic means will be deemed to be their original signatures for all purposes.

(o)

The Parties acknowledge that neither Party is waiving any right it may have under the Settlement Agreement.

Confidentiality. (a)

Neither Party may disclose any Confidential Information to a third party, other than: (i)

To such Party’s employees, Lenders, investors, attorneys, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential;

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(ii)

To potential Lenders with the consent of Buyer, which consent will not be unreasonably withheld; provided, however, that disclosure (1) of cash flow and other financial projections to any potential Lender or investor in connection with a potential loan or tax equity investment; or (2) to potential Lenders or investors with whom Seller has negotiated (but not necessarily executed) a term sheet or other similar written mutual understanding, will not require such consent of Buyer; provided further, that in each case such potential Lender or investor has a need to know such information and has agreed to keep such terms confidential;

(iii)

To Buyer’s Procurement Review Group, as defined in D.02-08071, or Buyer’s Cost Allocation Mechanism Group, as defined in D.06-07-029 and D.08-09-012, and pursuant to the Settlement Agreement and related Decisions, subject to a protective order applicable to Buyer’s Procurement Review Group or Buyer’s Cost Allocation Mechanism Group;

(iv)

With respect to Confidential Information other than nonpublic financial information of Seller supplied to Buyer pursuant to Section 3.20, to the CPUC, the CEC or the FERC, under seal for any regulatory purpose, including policymaking, but only provided that the confidentiality protections from the CPUC under Section 583 of the California Public Utilities Code or other statute, order or rule offering comparable confidentiality protection are in place before the communication of such Confidential Information;

(v)

In order to comply with any Applicable Law or any exchange, Control Area or CAISO rule, or order issued by a court or entity with competent jurisdiction over the disclosing party, other than to those entities set forth in Section 9.09(a)(vi);

(vi)

In order to comply with any Applicable Law, including applicable regulation, rule, subpoena, or order of the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, or any discovery or data request of the CPUC;

(vii)

To representatives of a Party’s credit ratings agencies who have a need to review the terms and conditions of this Agreement for the purpose of assisting the Party in evaluating this Agreement for credit rating purposes or with respect to the potential impact of this Agreement on the Party’s financial reporting obligations, in each case subject to confidentiality restrictions no less stringent than as set forth in this Agreement; and

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(viii) As may reasonably be required to participate in WREGIS or other process recognized under Applicable Laws for the registration, transfer or ownership of Green Attributes associated with the Related Products.

9.10

(b)

In connection with requirements, requests or orders to produce documents or information in the circumstances provided in Sections 8.03 and 9.09(a)(vi) (“Disclosure Order”) each Party shall, to the extent practicable, use reasonable efforts to (i) notify the other Party before disclosing the confidential information, and (ii) prevent or limit such disclosure. After using such reasonable efforts, the disclosing party may not be (x) prohibited from complying with a Disclosure Order, or (y) liable to the other Party for monetary or other damages incurred in connection with the disclosure of any terms or conditions of this Agreement which are the subject of such Disclosure Order.

(c)

Except as provided in clause (y) of Section 9.09(b), the Parties are entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, the confidentiality obligations set forth in this Section 9.09.

Insurance. (a)

As of the Effective Date and throughout the Term (and for such additional periods as may be specified in this Section 9.10), Seller shall, at its own expense, provide and maintain in effect the insurance policies and minimum limits of coverage specified in this Section 9.10, and such additional coverage as may be required by Applicable Law, with insurance companies which are authorized to do business in the state in which the services are to be performed and which have an A.M. Best’s Insurance Rating of not less than A-:VII. The minimum insurance requirements specified in this Section 9.10 do not in any way limit or relieve Seller of any obligation assumed elsewhere in this Agreement, including, but not limited to, Seller’s defense and indemnity obligations. (i)

Workers’ Compensation Insurance with the statutory limits required by the state having jurisdiction over Seller’s employees;

(ii)

Employer’s Liability Insurance with limits of not less than:

1)

Bodily injury by accident – One Million dollars ($1,000,000) each accident;

2)

Bodily injury by disease – One Million dollars ($1,000,000) policy limit; and

3)

Bodily injury by disease – One Million dollars ($1,000,000) each employee; and

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(iii)

Commercial General Liability Insurance, (which, except with the prior written consent of Buyer and subject to Sections 9.10(a)(ii)(1) and (2), shall be written on an “occurrence,” not a “claims-made” basis), covering all operations by or on behalf of Seller arising out of or connected with this Agreement, including coverage for bodily injury, broad form property damage, personal and advertising injury, products/completed operations, and contractual liability. Such insurance shall bear a combined single limit per occurrence and annual aggregate of not less than one million dollars ($1,000,000), exclusive of defense costs, for all coverages. Such insurance shall contain standard cross-liability and severability of interest provisions.

If Seller elects, with Buyer’s written concurrence, to use a “claims made” form of Commercial General Liability Insurance, then the following additional requirements apply: 1)

The retroactive date of the policy must be prior to the Effective Date; and

2)

Either the coverage must be maintained for a period of not less than four years after the Agreement terminates, or the policy must provide for a supplemental extended reporting period of not less than four years after the Agreement terminates.

(iv)

Commercial Automobile Liability Insurance covering bodily injury and property damage with a combined single limit of not less than $1,000,000 per occurrence. Such insurance shall cover liability arising out of Seller’s use of all owned (if any), non-owned and hired automobiles in the performance of the Agreement.

(v)

Umbrella/Excess Liability Insurance, written on an “occurrence,” not a “claims-made” basis, providing coverage excess of the underlying Employer’s Liability, Commercial General Liability, and Commercial Automobile Liability insurance, on terms at least as broad as the underlying coverage, with limits of not less than $10,000,000 per occurrence and in the annual aggregate. The insurance requirements of this Section 9.10 can be provided by any combination of Seller’s primary and excess liability policies.

(b)

The insurance required in Section 9.10(a) apply as primary insurance to, without a right of contribution from, any other insurance maintained by or afforded to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, and employees, regardless of any conflicting provision in Seller's policies to the contrary. To the extent permitted by Applicable Law, Seller and its insurers are required to waive all rights of recovery from or subrogation against Buyer, its subsidiaries and affiliates, and their respective

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officers, directors, shareholders, agents, employees and insurers. The Commercial General Liability and Umbrella/Excess Liability insurance required above shall name Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents and employees, as additional insureds for liability arising out of Seller’s construction, ownership or Operation of the Generating Facility.

9.11

(c)

At the time this Agreement is executed, or within a reasonable time thereafter, and within a reasonable time after coverage is renewed or replaced, Seller shall furnish to Buyer certificates of insurance evidencing the coverage required in this Section 9.10, written on forms and with deductibles reasonably acceptable to Buyer. All deductibles, co-insurance and self-insured retentions applicable to the insurance above shall be paid by Seller. All certificates of insurance shall note that the insurers issuing coverage shall endeavor to provide Buyer with at least 30 days’ prior written notice in the event of cancellation of coverage. Buyer’s receipt of certificates that do not comply with the requirements stated herein, or Seller’s failure to provide certificates, does not limit or relieve Seller of the duties and responsibility of maintaining insurance in compliance with the requirements in this Section 9.10 and does not constitute a waiver of any of the requirements in this Section 9.10.

(d)

If Seller fails to comply with any of the provisions of this Section 9.10, Seller, among other things and without restricting Buyer’s remedies under the Applicable Law or otherwise, shall, at its own cost and expense, act as an insurer and provide insurance in accordance with the terms and conditions above. With respect to the required Commercial General Liability, Umbrella/Excess Liability and Commercial Automobile Liability insurance, Seller shall provide a current, full and complete defense to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, employees, assigns, and successors in interest, in response to a third party claim in the same manner that an insurer would have, had the insurance been maintained in accordance with the terms and conditions set forth above.

(e)

Seller has the right to self-insure to comply with Seller’s obligations under this Section 9.10. The insurance carrier or carriers and form of policy (including any deductible amount), or any plan for self-insurance shall be subject to review and approval by Buyer, which approval may not be unreasonably withheld, conditioned or delayed.

Nondedication. Notwithstanding any other provisions of this Agreement, neither Party dedicates any of the rights that are or may be derived from this Agreement or any part of its facilities involved in the performance of this Agreement to the public or to the service provided under this Agreement, and such service shall cease upon termination of this Agreement.

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9.12

Mobile Sierra. Notwithstanding any provision of this Agreement, neither Party will seek, nor will they support any third party in seeking, to prospectively or retroactively revise the rates, terms, or conditions of service of this Agreement through application or complaint to FERC pursuant to the provisions of Section 205, 206, or 306 of the Federal Power Act, or any other provisions of the Federal Power Act, absent prior written agreement of the Parties. Further, absent the prior agreement in writing by both Parties, the standard of review for changes to the rates, terms or conditions of service of this Agreement proposed by a Party, a non-Party or the FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 US 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 US 348 (1956).

9.13

Seller Ownership and Control of Generating Facility. Seller agrees, that, in accordance with FERC Order No. 697, upon request of Buyer, Seller shall submit a letter of concurrence in support of an affirmative statement by Buyer that the contractual arrangement set forth in this Agreement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR Section 35.42. Seller also agrees that it will not, in filings, if any, made subject to Order Nos. 652 and 697, claim that the contractual arrangement set forth in this Agreement conveys ownership or control of generation capacity from Seller to Buyer.

9.14

Simple Interest Payments. Except as specifically provided in this Agreement, any outstanding and past due amounts owing and unpaid by either Party under the terms of this Agreement shall be eligible to receive a Simple Interest Payment calculated using the Interest Rate for the number of days between the date due and the date paid.

9.15

Payments. Payments to be made under this Agreement shall be made, at Seller’s option, by check or electronic wire funds transfer.

9.16

Provisional Relief. The Parties acknowledge and agree that irreparable damage would occur if certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or the other security, to seek a preliminary injunction, temporary restraining order, or other provisional relief as a remedy for a breach of Sections 3.01, 3.02, 3.03, or 9.09 in any court of competent jurisdiction, notwithstanding the obligation to submit all other disputes (including all Claims for monetary damages under this Agreement) to arbitration pursuant to Section 10.01. The Parties further acknowledge and agree that the results of such arbitration may be rendered ineffectual without such provisional relief.

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Such a request for provisional relief does not waive a Party’s right to seek other remedies for the breach of the provisions specified above in accordance with Section 10.01, notwithstanding any prohibition against claim-splitting or other similar doctrine. The other remedies that may be sought include specific performance and injunctive or other equitable relief, plus any other remedy specified in this Agreement for such breach of the provision, or if this Agreement does not specify a remedy for such breach, all other remedies available at law or equity to the Parties for such breach. *** End of Article Nine ***

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ARTICLE TEN.

DISPUTE RESOLUTION

10.01 Dispute Resolution. Other than requests for provisional relief under Section 9.16, any and all disputes, Claims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which Disputes the Parties have been unable to resolve by informal methods, will first be submitted to mediation in accordance with the procedures described in Section 10.02, and if the Dispute is not resolved through mediation, then for final and binding arbitration in accordance with the procedures described in Section 10.03. 10.02 Mediation. Either Party may initiate mediation by providing Notice to the other Party of a written request for mediation, setting forth a description of the Dispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the panel of neutrals from JAMS or any other mutually acceptable non-JAMS Mediator, and in scheduling the time and place of the mediation. Such selection and scheduling will be completed within 45 days after Notice of the request for mediation. Unless otherwise agreed to by the Parties, the mediation will not be scheduled for a date that is greater than 120 days from the date of Notice of the request for mediation. The Parties covenant that they will participate in the mediation, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and costs will be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, will not be subject to discovery and will be confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them; provided, however, that evidence that is otherwise admissible or discoverable will not be rendered inadmissible or non-discoverable as a result of its use in the mediation. 10.03 Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation in accordance with Section 10.02 by providing Notice of a demand for binding arbitration before a single, neutral arbitrator (the “Arbitrator”) at any time following the unsuccessful conclusion of the mediation provided for in Section 10.02.

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The Parties will cooperate with one another in selecting the Arbitrator within 60 days after Notice of the demand for arbitration and will further cooperate in scheduling the arbitration to commence no later than 180 days from the date of Notice of the demand. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator will be appointed as provided for in California Code of Civil Procedure Section 1281.6. To be qualified as an Arbitrator, each candidate must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator will be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon Notice of a Party’s demand for binding arbitration, such Dispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, will be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regard to principles of conflicts of laws. Except as provided for in this Section 10.03, the arbitration will be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated. Absent the existence of such rules and procedures, the arbitration will be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration will be in Los Angeles, California, and discovery will be limited as follows: (a)

Before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment);

(b)

The initial disclosure will occur within 30 days after the initial conference with the Arbitrator or at such time as the Arbitrator may order;

(c)

Discovery may commence at any time after the Parties’ initial disclosure;

(d)

The Parties will not be permitted to propound any interrogatories or requests for admissions;

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(e)

Discovery will be limited to 25 document requests (with no subparts), three lay witness depositions, and three expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents);

(f)

Each Party is allowed a maximum of three expert witnesses, excluding rebuttal experts;

(g)

Within 60 days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding;

(h)

Within 30 days after the initial expert disclosure, the Parties may designate a maximum of two rebuttal experts;

(i)

Unless the Parties agree otherwise, all direct testimony will be in form of affidavits or declarations under penalty of perjury; and

(j)

Each Party shall make available for cross-examination at the arbitration hearing its witnesses whose direct testimony has been so submitted.

Subject to Article Seven, the Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections 3.01, 3.02, 3.03 or 9.09. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator must, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs will be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail. Until such award is made, however, the Parties will share equally in paying the costs of the arbitration. *** End of Article Ten ***

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EXHIBIT A Definitions For purposes of this Agreement, the following terms and variations thereof have the meanings specified or referred to in this Exhibit A: “Actual HR” means the Heat Rate that must be used in accordance with and subject to the terms set forth in Section 2(a)(ii) of Exhibit S, which Heat Rate Buyer shall calculate, on the date of the commencement of the First Compliance Period, using the following formula: Actual HRn = The average of the Daily HRn for each delivery or flow date in the two (2) year period immediately preceding the commencement of the First Compliance Period Where: Daily HRn = [EPn – VOMn] / [GPn + GTn] Where: EPn = The average of the Day-Ahead hourly electric energy prices, as determined by the Integrated Forward Market (as defined in the CAISO Tariff) for (i) SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor, if Buyer is SCE or SDG&E, and (ii) NP15 Existing Zone Generation Trading Hub (formerly known as NP15), or its successor, if Buyer is PG&E; VOMn = Calendar month avoided variable O&M for the applicable month ($/kWh), per the Decision and CPUC Resolution E-4246; GPn = The applicable daily gas price index, which is (i) Platt’s Gas Daily (currently SoCalGas gas indices), if Buyer is SCE or SDG&E, or (ii) Platt’s Gas Daily (currently SoCalGas and PG&E Malin gas indices), if Buyer is PG&E; and GTn = The gas transportation rate for the applicable month, per CPUC Resolution E-4246. “Additional GHG Documentation” means the documentation necessary to allocate Free Allowances to electric energy delivered by Seller to Buyer, which documentation consists of the following, in each case for the time-period to which the Free Allowances are to apply: (a) the total amount of GHG emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, the Useful Thermal Energy Output of the Generating Facility, and the electric energy delivered to Buyer; (b) the Useful Thermal Energy Output of the Generating Facility; (c) the total electric energy produced by the Generating Facility, the electric energy

Exhibit A

Definitions

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Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

used to the serve the Site Host Load, and the electric energy delivered to Buyer; and (d) total fuel usage of the Generating Facility. “Agreement” has the meaning set forth in the Preamble. “Allowance” means a limited tradable authorization (whether in the form of a credit, allowance or other similar right), allocated to, issued to or purchased by, Seller, the Site Host or a Related Entity of Seller, with respect to the Generating Facility, to emit one MT of Greenhouse Gas, in accordance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), and as applied to the Greenhouse Gas emitted by the Generating Facility. “Allowance Cost” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “Allowed Firm Energy” is determined in Section 3(l) of Exhibit D. “Allowed Hourly Energy”, or “E”, is determined in Section 3(f) of Exhibit D. “Allowed Payment Energy”, or “APE”, is determined in Section 2(c) of Exhibit D. “Ambient Outage” means reductions in capacity due to that status of, or variations in, Site Host Load or ambient weather conditions. “Annual GHG Reports” has the meaning set forth in Section 3(a) of Exhibit S. “Applicable HR” has the meaning set forth in Section 1 of Exhibit S. “Applicable Laws” means all constitutions, treaties, laws, ordinances, rules, regulations, interpretations, permits, judgments, decrees, injunctions, writs and orders of any Governmental Authority or arbitrator that apply to either or both of the Parties, the Generating Facility or the terms of this Agreement. “Arbitrator” has the meaning set forth in Section 10.03. “As-Available Capacity”, or “AAC”, is determined in Section 3(c) of Exhibit D. “As-Available Capacity Payment”, or “ACP”, is determined in Section 3(b) of Exhibit D. “As-Available Capacity Price” means the price adopted by the CPUC in the Decision and in subsequent rulings of the CPUC implementing the Decision, or pursuant to any such other formula as the CPUC may adopt from time to time for As-Available Capacity Payments to be made to Buyer’s Qualifying Cogeneration Facilities for the applicable year, as set forth in Section 3(b) of Exhibit D, in dollars per kW-year.

Exhibit A

Definitions

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“As-Available Contract Capacity” means the electric energy generating capacity that Seller provides on an as-available basis for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). “Availability Credit Factor”, or “ACF”, is determined in Section 3(i) of Exhibit D. “Availability Incentive Payments” has the meaning set forth in the CAISO Tariff. “Availability Penalty Factor”, or “APF”, is determined in Section 3(n) of Exhibit D. “Availability Standards” has the meaning set forth in the CAISO Tariff. “Bankrupt” means with respect to any Person, such Person: (a) Files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it (which petition is not dismissed within 90 days); (b) Makes an assignment or any general arrangement for the benefit of creditors; (c) Otherwise becomes bankrupt or insolvent (however evidenced); (d) Has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets; or (e) Is generally unable to pay its debts as they fall due. “Benchmark Capacity” is determined, as applicable, in Section 3(a) of Exhibit D-1, Section 3(a) of Exhibit D-2, and Section 9(a) of Exhibit E. “Burner Tip Gas Price” or “BTGP” has the meaning set forth in Section 1 of Exhibit S. “Business Day” means any day except a Saturday, Sunday, the Friday after the United States Thanksgiving holiday, or a Federal Reserve Bank holiday that begins at 8:00 a.m. and end at 5:00 p.m. local time for the Party sending a Notice or payment or performing a specified action. “Buyer” has the meaning set forth in the Preamble. “Buyer Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy produced by the Generating Facility. “Buyer Parent Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy delivered to the CAISO for the CAISO Global Resource ID associated with the Generating Facility.

Exhibit A

Definitions

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Buyer Projected Energy Forecast” has the meaning set forth in Section 2(a) of Exhibit G. “CAISO” means the California Independent System Operator Corporation or successor entity that dispatches certain generating units, supplies certain loads and controls the transmission facilities of entities that (a) own, operate and maintain transmission lines and associated facilities or have entitlements to use certain transmission lines and associated facilities, and (b) have transferred to the CAISO or its successor entity operational control of such facilities or entitlements. “CAISO-Approved Meter” means any revenue quality, electric energy measurement meter furnished by Seller, that (a) is designed, manufactured and installed in accordance with the CAISO’s metering requirements, or, to the extent that the CAISO’s metering requirements do not apply, Prudent Electrical Practices, and (b) includes all of the associated metering transformers and related appurtenances that are required in order to measure the net electric energy output from the Generating Facility. “CAISO-Approved Quantity” means the total quantity of electric energy that Buyer Schedules with the CAISO and the CAISO approves in its final schedule which is published in accordance with the CAISO Tariff. “CAISO Charges” means the debits, costs, fees, penalties, sanctions, interest or similar charges, including imbalance energy charges, that are directly assigned by the CAISO to the CAISO Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement. “CAISO Charges Invoice” has the meaning set forth in Section 5 of Exhibit G. “CAISO Controlled Grid” has the meaning set forth in the CAISO Tariff. “CAISO Forced Outage Report” means a complete copy of a forced outage report in a form reasonably acceptable to Buyer which includes detailed information regarding the event, including the affected Generating Unit, outage start date and time, estimation of outage duration, MW unavailable and summary of work to be performed. “CAISO Global Resource ID” means the number or name assigned by the CAISO to the CAISOApproved Meter. “CAISO Revenues” means the credits, fees, payments, revenues, interest or similar benefits, including imbalance energy payments, that are directly assigned by the CAISO to the CAISO Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement.

Exhibit A

Definitions

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“CAISO Tariff” means the California Independent System Operator Corporation Operating Agreement and Tariff, including the rules, protocols, procedures and standards attached thereto, as the same may be amended or modified from time to time and approved by the FERC. “Capacity Attributes” means any and all current or future defined characteristics, certificates, tag, credits, ancillary service attributes, or accounting constructs, howsoever entitled, other than Resource Adequacy Benefits, attributed to or associated with the electricity generating capability of the Generating Facility. “Capacity Credit Hours”, or “CCH”, is determined in Section 3(m) of Exhibit D. “Capacity Credit Period” is determined in Section 3(b)(iv) of Exhibit E. “Capacity Payment Allocation Factors”, or “CAF”, means the TOD Period factors which are used to calculate the TOD Period Capacity Payment, as set forth in the table in Section 3(a) of Exhibit D. “Capacity Performance Requirement”, or “CR”, means the values set forth in Section 1.04. “CARB” means California Air Resources Board, or any successor entity. “CARB Annual Report” has the meaning set forth in Section 3(a)(i) of Exhibit S. “CARB Mandatory GHG Emissions Annual Report” means the mandatory reporting regulations approved by CARB in December 2007, which became effective in January 2009, pursuant to the requirements set forth in the California Global Warming Solutions Act of 2006 for the reporting of Greenhouse Gas by major sources. “CEC” means the California Energy Commission, or any successor entity. “CFR” means the Code of Federal Regulations, as may be amended from time to time. “Check Meter” means the Buyer revenue-quality meter section or meter(s), which Buyer may require at its discretion, as set forth in Section 3.08(b) and will include those devices normally supplied by Buyer or Seller under the applicable utility Electric Service Requirements. “Claiming Party” has the meaning set forth in Section 5.02. “Claims” means all third party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys’ fees and court costs, whether incurred by settlement or otherwise, and whether such claims or actions are threatened or filed before or after the termination of this Agreement. “Collateral Assignment Agreement” has the meaning set forth in Section 9.05.

Exhibit A

Definitions

Page 5

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Confidential Information” means all oral or written communications exchanged between the Parties on or after the Effective Date relating to the implementation of this Agreement, including information related to Seller’s compliance with operating and efficiency standards applicable to a “qualifying cogeneration facility” (as contemplated in 18 CFR Part 292, Section 292.205). Confidential Information does not include (i) information which is in the public domain as of the Effective Date or which comes into the public domain after the Effective Date from a source other than from the other Party, (ii) information which either Party can demonstrate in writing was already known to such Party on a non-confidential basis before the Effective Date, (iii) information which comes to a Party from a bona fide third-party source not under an obligation of confidentiality, or (iv) information which is independently developed by a Party without use of or reference to Confidential Information or information containing Confidential Information. “Control Area” means the electric power system (or combination of electric power systems) under the operational control of the CAISO or any other electric power system under the operational control of another organization vested with authority comparable to that of the CAISO. “Converted Physical Trade”, or “CPT”, means the quantity from Physical Trades, in MWh, that did not pass CAISO’s physical validation of the IFM. “Converted Physical Trade Price” means the price, in dollars per MWh, used by the CAISO to settle the quantity, in MWh, associated with the Converted Physical Trade. “Costs” means, with respect to the Non-Defaulting Party, brokerage fees, commissions, legal expenses and other similar third party transaction costs and expenses reasonably incurred by such Party in entering into any new arrangement which replaces this Agreement. “CPUC” means the California Public Utilities Commission, or any successor entity. “CPUC Approval” means a final and non-appealable order of the CPUC, without conditions or

modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. “Curtailment Period” means a time period for which Seller is requested by CAISO or a Transmission Provider to curtail its Power Product for Force Majeure or otherwise. “D.” has the meaning set forth in Recital A.

Exhibit A

Definitions

Page 6

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Day-Ahead” has the meaning set forth in the CAISO Tariff. “Day-Ahead Market” has the meaning set forth in the CAISO Tariff. “Day-Ahead Price” means the LMPQF, as set forth in Section 1 of Exhibit S. “Day-Ahead Schedule” has the meaning set forth in the CAISO Tariff. “Decision” has the meaning set forth in Recital A. “Defaulting Party” has the meaning set forth in Section 6.01(a). “Delivery Point” has the meaning set forth in Section 1.03. “Disclosure Order” has the meaning set forth in Section 9.09(b). “Dispute” has the meaning set forth in Section 10.01. “Early Termination Date” has the meaning set forth in Section 6.02(a). “Earned Capacity Hours”, or “ECH”, means the number of firm capacity equivalent available hours determined by dividing the Firm TOD Energy by the Firm Contract Capacity, as set forth in Section 3(j) of Exhibit D. “Effective Date” has the meaning set forth in the Preamble. “Emergency Condition” has the meaning set forth in the Transmission Provider’s LGIA or SGIA with Seller, or the distribution-level FERC-jurisdictional interconnection agreement with Seller, as applicable; provided, however, that if Seller interconnects pursuant to Tariff Rule 21, “Emergency Condition” means “Emergency”, as defined in such Tariff Rule 21. “Equitable Defense” means any Bankruptcy or other laws affecting creditors’ rights generally, and with regard to equitable remedies, the discretion of the court before which proceedings to obtain same may be pending. “Equity Investment” means an acquisition by a Lender of an ownership interest in the form of stock, membership or partnership interest of Seller or the immediate parent of Seller under which Seller retains the right to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s rights to enforce its ownership interest in Seller or the immediate parent of Seller, as applicable, in the event of a default by Seller or the immediate parent of Seller under Lender’s equity acquisition agreement or the partnership agreement, operating agreement, or other agreement governing the relationship between the equity owners of the Generating Facility. “Event of Default” has the meaning set forth in Section 6.01.

Exhibit A

Definitions

Page 7

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Existing PPA” has the meaning set forth in Section 1.01. “Existing Qualifying Cogeneration Facility” means a Generating Facility that commenced Parallel Operation before the Settlement Effective Date, and that, as of the Settlement Effective Date, (a) is a Qualifying Cogeneration Facility, and (b) is the generating facility under the Existing PPA. “Expected Term Year Energy Production” means the Metered Energy quantity expected to be produced by the Generating Facility during each Term Year, as set forth in Section 1.02(e). “Federal Funds Effective Rate” means the rate for that day opposite the caption “Federal Funds (effective)” as set forth in the weekly statistical release as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System. “FERC” means the Federal Energy Regulatory Commission, or any successor entity. “FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.05 in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. “Financial Consolidation Requirement” has the meaning set forth in Section 3.20(a). “Financial Incentives” means any and all financial incentives, benefits or credits associated with the Generating Facility, or the ownership or Operation thereof, or the electrical or thermal output of the Generating Facility, including any production or investment tax credits, real or personal property tax credits or sales or use tax credits, but not including any Green Attributes, Capacity Attributes or Resource Adequacy Benefits. “Firm Capacity Payment”, or “FCP”, has the meaning set forth in Section 3(g) of Exhibit D. “Firm Capacity Price” or “CP” is set forth in Section 1.06(a), in dollars per kW-year. “Firm Contract Capacity”, or “FCC”, means the monthly generating capacity that Seller commits to have available at the Site for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c).

Exhibit A

Definitions

Page 8

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Firm TOD Energy”, or “FE”, has the meaning set forth in Section 3(k) of Exhibit D. “First Compliance Period” means the first period of time for compliance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation). There will be no more than a single First Compliance Period. “First Penalty Month” has the meaning set forth in Section 3(b) of Exhibit I. “Floor Test Term” means the date that the First Compliance Period commences, for a period of three years. “Forced Outage” has the meaning set forth in the CAISO Tariff. “Force Majeure” means any event or circumstance to the extent beyond the control of, and not the result of the negligence of, or caused by, the Party seeking to have its performance obligation excused thereby, which by the exercise of due diligence such Party could not reasonably have been expected to avoid and which by exercise of due diligence it has been unable to overcome. Force Majeure does not include: (a) A failure of performance of any other Person, including any Person providing electric transmission service or fuel transportation to the Generating Facility, except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure event; (b) Failure to timely apply for or obtain Permits or other credits required to Operate the Generating Facility; (c) Breakage or malfunction of equipment (except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure); or (d) A lack of fuel of an inherently intermittent nature such as wind, water, solar radiation or waste gas or waste derived fuel. “Force Majeure Credit Value”, or “FCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Force Majeure curtailment requested by Buyer, determined in accordance with Section 3 of Exhibit D-1. “Forecast” means the hourly forecast of (a) the total electric energy production of the Generating Facility (in MWh) when the Generating Facility is not PIRP-eligible or Buyer is not Scheduling Coordinator net of the Site Host Load and Station Use, or (b) the available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator net of the Site Host Load and Station Use.

Exhibit A

Definitions

Page 9

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Forward Settlement Amount” means the Non-Defaulting Party’s Costs and Losses on the one hand, netted against its Gains, on the other. If the Non-Defaulting Party’s Gains exceed its Costs and Losses, then the Forward Settlement Amount shall be zero dollars. If the Non-Defaulting Party’s Costs and Losses exceed its Gains, then the Forward Settlement Amount shall be an amount owing to the Non-Defaulting Party. The Forward Settlement Amount does not include consequential, incidental, punitive, exemplary or indirect or business interruption damages. “Free Allowance” means any Allowance freely allocated to Seller or the Generating Facility by CARB or an authorized Governmental Authority (or any entity authorized by such Governmental Authority). “Free Allowance Notice” means the Notice, delivered by Seller to Buyer in accordance with this Agreement, that sets forth the aggregate quantity of Free Allowances received by Seller during the applicable time-period and sets forth the allocation of such Free Allowances in accordance with the following: (i)

The allocation of Free Allowances by the CARB (or any other Governmental Authority) to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable time-period; or

(ii)

If the CARB (or any other Governmental Authority) does not allocate Free Allowances received by Seller as described in subsection (i) above, then Seller shall set forth in the Free Allowance Notice the quantity of Free Allowances allocated to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable timeperiod (FAd) utilizing the following formula: FAd = FAt * [Ge/(Ge+ Gt)] * [Ed/(Esh + Ed)] Where: FAt = Total number of Free Allowances received by Seller with respect to the Generating Facility for the applicable time-period; Ge (in MTs) = Emissions of Greenhouse Gas attributed to the total amount of electric energy produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Gt (in MTs) = Emissions of Greenhouse Gas attributed to the Useful Thermal Energy Output produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the

Exhibit A

Definitions

Page 10

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Ed (in kWh) = Electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period; and Esh (in kWh) = Electric energy generated by the Generating Facility and used to serve the Site Host Load for the applicable time-period; or (iii)

If the CARB (or any other Governmental Authority) does not allocate the Free Allowances received by Seller, as described in (i) above, and there is no available formula in any applicable rule or regulation for the calculation of Ge and Gt, as described in (ii) above, then Seller shall include in the Free Allowance Notice the total amount of emissions of Greenhouse Gas attributed to the electric energy period (Ge, in MTs) and the Useful Thermal Energy Output (Gt, in MTs) produced by the Generating Facility for the applicable time-period based on the two following formulas: Ge = G * (Useful Power Output / (Useful Power Output + Useful Thermal Energy Output)) Gt = G * (Useful Thermal Energy Output / (Useful Power Output + Useful Thermal Energy Output)) Where: G (in MTs) = Total emissions of Greenhouse Gas produced by the Generating Facility for the applicable time-period; Useful Power Output (in MMBtu) = As defined in 18 CFR §292.202(g), or any successor thereto; Useful Thermal Energy Output (in MMBtu) = As defined in 18 CFR §292.202(h), or any successor thereto; Upon determining Ge and Gt in subsection (iii) above, Seller shall then calculate for and provide the quantity of Free Allowances attributed to electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period (FAd) using the formula set forth in subsection (ii) of this definition.

“GAAP” means generally accepted accounting principles for financial reporting in the United States, consistently applied.

Exhibit A

Definitions

Page 11

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Gains” means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), as of the Early Termination Date resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the gain of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remaining Term and shall include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the gain of economic benefits, then the NonDefaulting Party may use information available to it internally. “Generating Facility” means the Generating Unit(s) described in Section 1.02 and Exhibit B, including all other materials, equipment, systems, structures, features and improvements necessary for these Generating Units to produce electric energy and thermal energy, excluding the Site, land rights and interests in land. “Generating Unit” means one or more generating equipment combinations typically consisting of prime mover(s), electric generator(s), electric transformer(s), steam generator(s) and air emission control devices. The references to the term Generating Unit shall be applicable only to Generating Unit #1 and Generating Unit #3 throughout the Term. “Generating Unit #1” means the Generating Unit described in Section 1(a) of Exhibit B of this Agreement. “Generating Unit #3” means the Generating Unit described in Section 1(b) of Exhibit B of this Agreement. “Generation Operations Center” means the location of Buyer’s real-time operations personnel. “Generator Operator” means the Person that Operates the Generating Facility and performs the functions of supplying electric energy and interconnected operations services within the meaning of the NERC Reliability Standards.

Exhibit A

Definitions

Page 12

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Generator Operator Obligations” means the obligations of a Generator Operator as set forth in all applicable NERC Reliability Standards. “Generator Owner” means the Person that owns the Generating Facility and has registered with the NERC as the Person responsible for complying with all NERC Reliability Standards applicable to the owner of the Generating Facility. “Generator Owner Obligations” means the obligations of a Generator Owner as set forth in all applicable NERC Reliability Standards. “GHG Allowance Price” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “GHG Auction” means any auction or other sale-by-bid event applicable to California and by an authorized Governmental Authority (or any entity authorized by such Governmental Authority) for the sale of Allowances. “GHG Charges” has the meaning set forth in Section 1 of Exhibit S. “GHG Compliance Costs” means the cost of Allowances, as determined in accordance with Exhibit S. “GHG Floor Test” has the meaning set forth in Section 2(a) of Exhibit S. “Governmental Authority” means (a) any federal, state, local, municipal or other government, (b) any governmental, regulatory or administrative agency, commission, or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power, or (c) any court or governmental tribunal. “Governmental Charges” has the meaning as set forth in Section 8.02. “Green Attributes” means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to

Exhibit A

Definitions

Page 13

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1 (3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. “Greenhouse Gas” or “GHG” means emissions released into the atmosphere of carbon dioxide (CO2), nitrous oxide (N2O) and methane (CH4), which are produced as the result of combustion or transport of fossil fuels. Other greenhouse gases may include hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6), which are generated in a variety of industrial processes. Greenhouse gases may be defined or expressed in terms of a MT of CO2equivalent, in order to allow comparison between the different effects of gases on the environment; provided, however, that the definition of the term “Greenhouse Gas”, as set forth in

1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program.

Exhibit A

Definitions

Page 14

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

the immediately preceding sentence, shall be deemed revised to include any update or other change to such term by the CARB or any other Governmental Authority. “Heat Rate” means, for purposes of this Agreement, the value obtained, in BTU per kWh, when the fuel input, on a Higher Heating Value basis, in BTU is divided by generation, net of Station Use, in kWh. “Higher Heating Value” means the high or gross heat content of the fuel with the heat of vaporization included (the water vapor is assumed to be in a liquid state). “Host Site” means the site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Related Entities located at such site. “Hour-Ahead Scheduling Deadline” means 30 minutes before the deadline established by the CAISO for the submission of schedules for the applicable hour. “Hourly Credit Value” is determined, as applicable, in Section 3(b) of Exhibit D-1, Section 3(b) of Exhibit D-2 and Section 9(b)(i) of Exhibit E. “Hourly Debit Value” is determined in Section 9(b)(ii) of Exhibit E. “Hourly Location Adjustment”, or “LA”, has the meaning set forth in Section 1 of Exhibit S. “Hourly Power Output” means an hourly rate of electric energy delivery, in kWh per hour, that is equal to the Metered Energy for one hour, in kWh, divided by one hour. “IFM” (i.e., the Integrated Forward Market) has the meaning set forth in the CAISO Tariff. “IFM Load Uplift Obligation” means the obligation of a Scheduling Coordinator to pay its share of unrecovered IFM Bid Costs (as defined in the CAISO Tariff) paid to resources through Bid Cost Recovery (as defined in the CAISO Tariff). “IFRS” has the meaning set forth in Section 3.20(b)(iii). “Incipient Event of Default” has the meaning set forth in Section 9.05(a). “Interconnection Study” means a study prepared by or on behalf of the Transmission Provider or the CAISO to evaluate the impact of the interconnection of the Generating Facility to the Transmission Provider’s electric system or the applicable Control Area operator’s electric grid. “Interest Rate” means an annual rate equal to the rate published in The Wall Street Journal as the “Prime Rate” (or, if more than one rate is published, the arithmetic mean of such rates) as of the date payment is due plus two percentage points; provided, however, that in no event shall the Interest Rate exceed the maximum interest rate permitted by Applicable Laws.

Exhibit A

Definitions

Page 15

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Inter-SC Trade” means a trade between Scheduling Coordinators of electric energy, Ancillary Service (as defined in the CAISO Tariff), or IFM Load Uplift Obligation in accordance with the CAISO Tariff. “JAMS” means the Judicial Arbitration and Mediation Services, Inc. or any successor entity. “kW” means a kilowatt (1,000 watts) of electric capacity or power output. “kWh” means a kilowatt-hour (1,000 watt-hours) of electric energy. “LAR” means local area reliability, which is any program of localized resource adequacy requirements established for jurisdictional load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by another Local Regulatory Authority having jurisdiction over the load serving entity. LAR may also be known as local resource adequacy, local RAR, or local capacity requirement in other regulatory proceedings or legislative actions. “LAR Showings” means the LAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction over the load serving entity. “Lease” means one or more agreements whereby Seller leases the Site(s) described in Section 1.02 and Exhibit B from a third party, the term of which lease begins on or before the Term Start Date and extends at least through the Term End Date. “Lender” means any third-party institution or entity or successor in interest or assignees that either (i) purchases the Generating Facility and then leases it to Seller under a Sale-Leaseback Transaction, or (ii) provides development, bridge, construction, or permanent debt or tax equity financing or refinancing (including an Equity Investment) for the Generating Facility to Seller or credit support in connection with this Agreement. “LGIA” (i.e., Large Generator Interconnection Agreement or Standard Large Generator Interconnection Agreement) has the meaning set forth in the CAISO Tariff. “Limited TOD Energy”, or “LE”, has the meaning set forth in Section 3(e) of Exhibit D. “LMPQF” has the meaning set forth in Section 1 of Exhibit S. “LMPTrading Hub” has meaning set forth in Section 1 of Exhibit S. “Local Regulatory Authority” has the meaning set forth in the CAISO Tariff. “Locational Marginal Price” has the meaning set forth in the CAISO Tariff.

Exhibit A

Definitions

Page 16

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Losses” means, with respect to any Party, an amount equal to the present value of the economic loss to it if any (exclusive of Costs), as of the Early Termination Date, resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the loss of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remainder of the Term and must include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the loss of economic benefits, then the Non-Defaulting Party may use information available to it internally. “MAEm” has the meaning set forth in Section 3(a) of Exhibit I. “MAE Failure” has the meaning set forth in Section 3(b) of Exhibit I. “Maintenance Credit Value”, or “MCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Maintenance Outage or a Major Overhaul which has been properly scheduled in accordance with Exhibit E. “Maintenance Debit Value” is a value indicating how much allowance is used when Seller requests credit for a Maintenance Outage or a Major Overhaul in accordance with Exhibit E. “Maintenance Outage” means a time period during which Seller plans to reduce the Power Output of the Power Product, in full or in part, in order to facilitate maintenance work on the Generating Facility, other than a Major Overhaul. “Major Overhaul” means a time period during which Seller plans to remove the Generating Facility from Operation in order to dismantle the Generating Facility’s equipment for inspections, repairs or replacement, with the goal that such equipment will be reassembled and made available for Operation. “Major Overhaul Allowance” is a value indicating a Term-Year maximum allowance with which Seller can request credit for a Major Overhaul in accordance with Exhibit E.

Exhibit A

Definitions

Page 17

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Market Disruption Event” means, with respect to any MHR Source, any of the following events: (i) the permanent discontinuation or material suspension of trading in the exchange or in the market specified for determining a Market Heat Rate; (ii) the temporary or permanent discontinuance or unavailability of the MHR Source; or (iii) the temporary or permanent closing of any exchange specified for determining a Market Heat Rate. For purposes of this definition, “temporary” means five (5) or more continuous Trading Days. “Market Heat Rate” means the 12-month forward market heat rate, calculated for each calendar pricing month utilizing the methodology set forth in Commission Decision 07-09-040 and Commission Resolution E-4246 for SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor. Unless otherwise agreed to by the Parties, this definition of Market Heat Rate will not be updated by any subsequent decision, ruling or order by the CPUC. “Maximum Allowed Capacity”, or “MAC”, is determined in Section 3(d) of Exhibit D. “Maximum Firm Capacity Payment”, or “MFCP”, means the maximum payment that Seller can earn during a year for the delivery of Firm Contract Capacity that is calculated in accordance with the procedure set forth in Section 3(h) of Exhibit D. “Mediator” has the meaning set forth in Section 10.02. “Metered Amounts” means the quantity of electric energy, expressed in kWh, as recorded by (i) the CAISO-Approved Meter(s), which quantity may include compensation factors introduced by the CAISO into the CAISO-Approved Meter(s), or (ii) Check Meter(s), as applicable. “Metered Energy” means the quantity of electric energy, expressed in kWh, as measured by (i) the CAISO-Approved Meter(s), which quantity will be adjusted so as not to include compensation factors, if any, introduced by the CAISO into the CAISO-Approved Meter(s) other than (x) electric energy consumed within the generator collection system as losses between the generator(s) and the high voltage side of the Generating Facility output transformer(s) and, (y) if applicable, the Generating Facility’s radial line losses, or (ii) Check Meters, as applicable, in each case for the specified Metering Interval. “Metering Interval” means the smallest measurement time period over which data are recorded by the CAISO-Approved Meters or Check Meters. “MHR Source” the relevant publications used to determine the Market Heat Rate. “Monthly Contract Payment” has the meaning set forth in Section 4.01. “Monthly Scheduling Fee” is described in Section 4(b) of Exhibit G. “MT” means metric ton(s). “MW” means a megawatt (1,000,000 watts) of electric capacity or power output.

Exhibit A

Definitions

Page 18

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“MWh” means a megawatt-hour (1,000,000 watt-hours) of electric energy or power output. “NERC” means the North American Electric Reliability Corporation, or any successor entity. “NERC Reliability Standards” means the most recent version of those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by the NERC and approved by the applicable regulatory authorities, which are available at http://www.nerc.com/files/Reliability_Standards_Complete_Set.pdf, or any successor thereto. “NERC Standards Non-Compliance Penalties” means any and all monetary fines, penalties, damages, interest or assessments by the NERC, the CAISO, the WECC, a Governmental Authority or any Person acting at the direction of a Governmental Authority arising from or relating to a failure to perform the obligations of Generator Operator or Generator Owner as set forth in the NERC Reliability Standards. “Net Contract Capacity”, or “NCC”, means the sum of Firm Contract Capacity and As-Available Contract Capacity, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). Net Contract Capacity may not exceed PMax. “Net Qualifying Capacity” has the meaning set forth in the CAISO Tariff. “Non-Availability Charges” has the meaning set forth in the CAISO Tariff. “Non-Defaulting Party” has the meaning set forth in Section 6.02. “Notice” means notices, requests, statements or payments provided in accordance with Section 9.07 and Exhibit N. “OMAR” means the Operational Metering Analysis and Reporting System operated and maintained by the CAISO as the repository of settlement quality meter data, or any successor thereto. “Operate,” “Operating,” or “Operation” means to provide (or the provision of) all the operation, engineering, purchasing, repair, supervision, training, inspection, testing, protection, use management, improvement, replacement, refurbishment, retirement, and maintenance activities associated with operating the Generating Facility in order to produce the Power Product in accordance with Prudent Electrical Practices. “Outage” has the meaning set forth in the CAISO Tariff. “Outage Schedule” has the meaning set forth in Section 2(a) of Exhibit R.

Exhibit A

Definitions

Page 19

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Outage Schedule Submittal Requirements” describes the obligations of Seller to submit maintenance and planned outage schedules (as defined in the CAISO Tariff under WECC rules) to Buyer 24 months in advance, as set forth in Exhibit R. “Parallel Operation” means the Generating Facility’s electrical apparatus is connected to the Transmission Provider’s system and the circuit breaker at the point of common coupling is closed. The Generating Facility may be producing electric energy or consuming electric energy at such time. “Party” has the meaning set forth in the Preamble. “Peak Months” means June, July, August and September. “Penalized As-Available Contract Capacity” has the meaning set forth in Section 3(b)(ii) of Exhibit I. “Penalized Firm Contract Capacity” has the meaning set forth in Section 3(b)(i) of Exhibit I. “Performance Tolerance Band Lower Limit” is determined in Section 1 of Exhibit K. “Performance Tolerance Band Upper Limit” is determined in Section 1 of Exhibit K. “Permits” means all applications, approvals, authorizations, consents, filings, licenses, orders, permits or similar requirements imposed by any Governmental Authority, or the CAISO, in order to develop, construct, Operate, maintain, improve, refurbish or retire the Generating Facility or to Forecast or deliver the electric energy produced by the Generating Facility to Buyer. “Person” means an individual, partnership, corporation, business trust, limited liability company, limited liability partnership, joint stock company, trust, unincorporated association, joint venture or other entity or a Governmental Authority. “PGA” (i.e., Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Physical Trade” has the meaning set forth in the CAISO Tariff. “Physical Trade Settlement Amount” means the dollar amount calculated in accordance with Exhibit L. “PIRP” (i.e., Participating Intermittent Resource Program) means the CAISO’s intermittent resource program initially established pursuant to Amendment No. 42 of the CAISO Tariff in Docket No. ER02-922-000, or any successor program that Buyer determines accomplishes a similar purpose. “PMax” has the meaning set forth in the CAISO Tariff.

Exhibit A

Definitions

Page 20

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“PNode” has the meaning set forth in the CAISO Tariff. “Power Output” means the average rate of electric energy delivery during one Metering Interval, converted to an hourly rate of electric energy delivery, in kWh per hour, that is equal to the product of Metered Energy for one Metering Interval, in kWh per Metering Interval, times the number of Metering Intervals in a one-hour period. “Power Product” means (a) the Net Contract Capacity and (b) all electric energy produced by the Generating Facility, net of all Station Use and any and all of the Site Host Load. “PPT” means Pacific Daylight time when California observes Daylight Savings Time and Pacific Standard Time otherwise. “Primary Fuel” means the fuel or combination of fuels that are provided for in the Permits applicable to the Generating Facility. “Product” means the Power Product and the Related Products. “Project” means the Generating Facility. “Prudent Electrical Practices” means those practices, methods and acts that would be implemented and followed by prudent operators of electric generating facilities in the Western United States, similar to the Generating Facility, during the relevant time period, which practices, methods and acts, in the exercise of prudent and responsible professional judgment in the light of the facts known at the time a decision was made, could reasonably have been expected to accomplish the desired result consistent with good business practices, reliability and safety. Prudent Electrical Practices includes, at a minimum, those professionally responsible practices, methods and acts described in the preceding sentence that comply with the manufacturer’s warranties, restrictions in this Agreement, and the requirement of Governmental Authorities, WECC standards, the CAISO and Applicable Laws. Prudent Electrical Practices shall include taking reasonable steps to ensure that: (a) Equipment, materials, resources and supplies, including spare parts inventories, are available to meet the Generating Facility’s needs; (b) Sufficient operating personnel are available at all times and are adequately experienced, trained and licensed as necessary to Operate the Generating Facility properly and efficiently, and are capable of responding to reasonably foreseeable emergency conditions at the Generating Facility and Emergencies whether caused by events on or off the Site; (c) Preventative, routine, and non-routine maintenance and repairs are performed on a basis that ensures reliable, long term and safe operation of the Generating Facility, Exhibit A

Definitions

Page 21

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

and are performed by knowledgeable, trained and experienced personnel utilizing proper equipment and tools; (d) Appropriate monitoring and testing are performed to ensure equipment is functioning as designed; (e) Equipment is not operated in a reckless manner, in violation of manufacturer’s guidelines or in a manner unsafe to workers, the general public or the Transmission Provider’s electric system, or contrary to environmental laws, permits or regulations or without regard to defined limitations, such as flood conditions, safety inspection requirements, operating voltage, current, volt ampere reactive (VAR) loading, frequency, rotational speed, polarity, synchronization, and control system limits; and (f) Equipment and components designed and manufactured to meet or exceed the standard of durability that is generally used for electric energy generation operations in the Western United States and will function properly over the full range of ambient temperature and weather conditions reasonably expected to occur at the Site and under both normal and emergency conditions. “PTSAi” has the meaning set forth in Section 2 of Exhibit L. “PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95-617, as amended from time to time. “QF PGA” (i.e., Qualifying Facility Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Qualifying Cogeneration Facility” means an electric energy generating facility that: (a)

Complies with the “qualifying cogeneration facility” definition and other requirements (including the requirements set forth in 18 CFR Part 292, Section 292.205) established by PURPA and any FERC rules as amended from time to time implementing PURPA, as set forth in 18 CFR Part 292, Section 292.203 et seq.; and

(b)

Has filed with the FERC (i) an application for FERC certification, pursuant to 18 CFR Part 292, Section 292.207(b)(1), which the FERC has granted, or (ii) a notice of selfcertification pursuant to 18 CFR Part 292, Section 292.207(a).

“RAR” means the resource adequacy requirements established for load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by a Local Regulatory Authority or other Governmental Authority having jurisdiction. “RAR Showings” means the RAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (or, to the extent authorized by the CPUC, to

Exhibit A

Definitions

Page 22

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

the CAISO), pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction. “Real-Time Forced Outage” means a Forced Outage which occurs only after 5:00 p.m. PPT on the day before the Trading Day. “Real-Time Market” has the meaning set forth in the CAISO Tariff. “Real-Time Price” means the Real-Time Market price for Uninstructed Imbalance Energy (as defined in the CAISO Tariff) or any successor price for short-term imbalance energy, as such price or successor price is defined in the CAISO Tariff, that would apply to the Generating Facility, which values are, as of the Effective Date, posted by the CAISO on its website. The values used in this Agreement will be those appearing on the CAISO website on the eighth Business Day of the calendar month following the month for which such prices are being applied. “Reference Market-Maker” means a leading dealer in the electric energy market that is not an Related Entity of either Party (or of a Trade Organization) and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker. “Related Entity” means, with respect to a party, any Person that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with such party. For purposes of this Agreement, “control” means the direct or indirect ownership of 50% or more of the outstanding capital stock or other equity interests having ordinary voting power. “Related Products” means (i) with respect to Resource Adequacy Benefits (a) that portion of the Resource Adequacy Benefits that are associated with the Firm Contract Capacity, and (b) to the extent that there are Resource Adequacy Benefits associated with the generating capacity of the Generating Facility other than the Firm Contract Capacity, that portion of the Resource Adequacy Benefits that are not associated with the Firm Contract Capacity and that are in excess of those Resource Adequacy Benefits used by Seller or by a Site Host, both in connection with the Host Site, to meet a known and established resource adequacy obligation under any Resource Adequacy Ruling at the point in time when the Resource Adequacy Benefits are to be used, and (ii) any Green Attributes, Capacity Attributes and all other attributes associated with the electric energy or capacity of the Generating Facility (but not including any Financial Incentives) that are in excess of those Green Attributes, Capacity Attributes or other attributes used, or retained for future use, by Seller or a Site Host, both in connection with the Host Site, to meet a known and established, at the point in time when the relevant attribute(s) are to be used or retained, obligation under Applicable Law. “Renewable Energy Credit” has the meaning set forth in Public Utilities Code Section 399.12(g), as may be amended from time to time or as further defined or supplemented by Applicable Law.

Exhibit A

Definitions

Page 23

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Resource Adequacy Benefits” means the rights and privileges attached to the Generating Facility that satisfy any Person’s resource adequacy obligations, as those obligations are set forth in any Resource Adequacy Rulings and shall include any local, zonal or otherwise locational attributes associated with the Generating Facility. “Resource Adequacy Resource” has the meaning set forth in the CAISO Tariff. “Resource Adequacy Rulings” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 0606-024, 06-07-031 and any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable Governmental Authority, as such CPUC decisions, rulings, laws, rules or regulations may be amended or modified from time to time during the Term. “RFO Agreement” means the Power Purchase and Sale Agreement between the Parties, dated July 2, 2012, as may be amended from time to time. “RPS Program” means the State of California Renewable Portfolio Standard Program, as codified at California Public Utilities Code Section 399.11, et seq. “Sale-Leaseback Transaction” means a transaction in which Seller (i) sells the Generating Facility to a Lender providing tax equity financing to Seller and (ii) leases the Generating Facility from Lender under an agreement authorizing Seller to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s right to terminate the lease in the event of a default by Seller as set forth in the agreement between Seller and Lender. “Schedule” means the action of the Scheduling Coordinator, or its designated representatives, of notifying, requesting, and confirming to the CAISO, the CAISO-Approved Quantity of electric energy. “Scheduled Amount” means the Day-Ahead Schedule comprised of the quantity (in MWh) of electric energy expected to be produced by the Generating Facility that is scheduled from Seller or Seller’s Scheduling Coordinator to Buyer in a Physical Trade in the IFM. “Scheduled Power Offline” is described in Section 3(b)(v) of Exhibit E. “Scheduling Coordinator” means a Person certified by the CAISO for the purposes of undertaking the functions specified in Exhibit G. “Scheduling Fee” means the Monthly Scheduling Fee and the SC Set-Up Fee. “SC Replacement Date” has the meaning set forth in Section 7(b) of Exhibit G. “SC Set-Up Fee” is described in Section 4(a) of Exhibit G.

Exhibit A

Definitions

Page 24

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“SC Trade Settlement Amount” means the amount(s) determined in accordance with Exhibit M. “SC Trade Tolerance Band” means the greater of (a) three percent of the Scheduled Amount or (b) one MW. “SDD Administrative Charge” has the meaning set forth in Section 2 of Exhibit K. “SDD Adjustment” means the adjustment, if any, to the Monthly Contract Payment, as determined in accordance with Exhibit K. “SDD Energy Adjustment” has the meaning set forth in Section 1 of Exhibit K. “SEC” means the United States Securities and Exchange Commission, or any successor entity. “Self-Schedule” has the meaning set forth in the CAISO Tariff. “Seller” has the meaning set forth in the Preamble. “Seller’s Day-Ahead Forecast” means the most recently updated Forecast submitted by 5:00 p.m. PPT on the day before the Trading Day. “Seller’s Energy Forecast” means Seller’s most recently updated Forecast submitted in accordance with Exhibit I. “Seller’s Final Energy Forecast” means Seller’s Energy Forecast as may be updated for Forced Outages that occur after the Hour-Ahead Scheduling Deadline, but not for Ambient Outages. “Settlement Agreement” has the meaning set forth in Recital C. “Settlement Effective Date” has the meaning set forth in Recital D. “Settlement Interval” has meaning set forth in the CAISO Tariff. “Settling Parties” has the meaning set forth in Recital B. “SGIA” (i.e., Small Generator Interconnection Agreement) means the form of Interconnection Request (as defined in the CAISO Tariff) pertaining to a Small Generating Facility (as defined in the CAISO Tariff), which is attached to the CAISO Tariff as Appendix T. “Simple Interest Payment” means a dollar amount calculated by multiplying the: (a) Dollar amount on which the Simple Interest Payment is based; by (b) Federal Funds Effective Rate or Interest Rate as applicable; by (c) The result of dividing the number of days in the calculation period by 360.

Exhibit A

Definitions

Page 25

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Site” means the real property on which the Generating Facility is located, as further described in Section 1.02(b) and Exhibit B. “Site Control” means that Seller (a) owns the Site, (b) is the lessee of the Site under a Lease, (c) is the holder of a right-of-way grant or similar instrument with respect to the Site, or (d) is managing partner or other Person authorized to act in all matters relating to the control and Operation of the Site and Generating Facility. “Site Host” means the Person or Persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating Facility. “Site Host Load” means the electric energy and capacity produced by or associated with the Generating Facility that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b). “SLIC” means Scheduling and Logging system for the CAISO. “Station Use” means the electric energy produced by the Generating Facility that is (a) used within the Generating Facility to power the lights, motors, control systems and other electrical loads that are necessary for Operation, and (b) consumed within the Generating Facility’s electric energy distribution system as losses needed to deliver electric energy to the Site Host Load, and (c) consumed within the generator collection system as losses between the generator(s) and the high voltage side of the Generating Facility output transformer(s). “Successor” has the meaning set forth in Section 3.20(b)(iii). “Supply Plan” has the meaning set forth in the CAISO Tariff. “System Emergency” has the meaning set forth in the CAISO Tariff. “Tariff Rule 21” means the interconnection standards of the Transmission Provider for distributed generation adopted by the CPUC in Decisions 00-11-001 and 00-12-037, as modified by the CPUC. “Telemetry System” means a system of electronic components that interconnects the CAISO and the Generating Facility in accordance with the CAISO’s applicable requirements as set forth in Section 3.09. “Term” has the meaning set forth in Section 1.01. “Term End Date” has the meaning set forth in Section 1.01. “Termination Payment” has the meaning set forth in Section 6.03. “Term Start Date” has the meaning set forth in Section 1.01.

Exhibit A

Definitions

Page 26

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Term Year” means a 12-month period beginning on the first day of the Term and each successive 12-month period thereafter. “TOD Period” means the time of delivery period used to calculate the Monthly Contract Payment set forth in Section 4 of Exhibit D. “TOD Period Capacity Payment” means the monthly payment to be calculated and made by Buyer to Seller for Power Product capacity during each TOD Period for the month for which a calculation is being performed, as set forth in Section 3(a) of Exhibit D, in dollars. “TOD Period Energy Payment” means the monthly payment to be calculated and made by Buyer to Seller for the Metered Energy during each TOD Period for the month for which a calculation is being performed, as set forth in Section 2(a) of Exhibit D, in dollars. “TOD Period Energy Price” means the price used to calculate the TOD Period Energy Payment, as set forth in Exhibit S and referenced in Section 2(b) of Exhibit D, in dollars per kWh. “TOU” has the meaning set forth in Section 1 of Exhibit S. “Trade Organizations” means the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, and the Independent Energy Producers Association. “Trading Day” means the day in which Day-Ahead trading occurs in accordance with the WECC Preschedule Calendar (as found on the WECC’s website). “Transmission Curtailment Credit Value” or “TCV” is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, as determined in accordance with Section 3 of Exhibit D-2. “Transmission Provider” means any Person responsible for the interconnection of the Generating Facility with the interconnecting utility’s electrical system or the CAISO Controlled Grid or transmitting the Metered Energy on behalf of Seller from the Generating Facility to the Delivery Point. “Transition EEI Agreement” means that certain Edison Electric Institute Master Power Purchase & Sale Agreement, together with the Cover Sheet, any amendments and annexes thereto (including the Collateral Annex and Paragraph 10 thereto) between Buyer and Seller, dated October 15, 2012. “Transition RA Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (RA Capacity), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement.

Exhibit A

Definitions

Page 27

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

“Transition Tolling Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (Energy Only UC Toll (Kern Pipeline – financially settled gas)), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement. “Uninstructed Deviation GMC Rate” means the administrative grid management charge applied by the CAISO to Uninstructed Deviations (as defined in the CAISO Tariff) using the absolute value for the Uninstructed Deviations by Settlement Interval. “Uninstructed Deviation Penalty” means the penalty set forth in the CAISO Tariff. “Useful Thermal Energy Output” has the meaning set forth in 18 CFR §292.202(h) and modified by the Energy Policy Act of 2005, or any successor thereto. “VOM” has the meaning set forth in Section 1 of Exhibit S. “Web Client” has the meaning set forth in Section 2(a) of Exhibit R. “Web Scheduler” has the meaning set forth in Section 2 of Exhibit E. “WECC” means the Western Electricity Coordinating Council, the regional reliability council for the western United States, northwestern Mexico, and southwestern Canada, or any successor entity. “WREGIS” means the Western Renewable Energy Generation Information System, or any successor thereto. *** End of Exhibit A ***

Exhibit A

Definitions

Page 28

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT B Generating Facility and Site Description 1.

Generating Facility Description. (a)

Generating Unit Features. Each Generating Unit has:

(b)

(i)

One General Electric Frame 7 gas turbine, with a nominal electric capacity rating of 76.56 MW;

(ii)

A bypass exhaust stack for simple cycle operation; and

(iii)

A heat recovery steam generator (HRSG) that is used to turn produced water from the oil field into steam for use in an enhanced oil recovery system.

Interconnection Utility System The Generating Facility has been operating in parallel with SCE’s Transmission System since 1988. The Generating Facility consists of a SCE designed and built 220kV switchyard with connections to the four generating units and to a SCE owned transmission line which transmits power to the SCE owned Magunden substation.

(d)

Measurement of Useful Thermal Energy Output Seller sells useful thermal energy output (steam) to Chevron U.S.A. Inc. for use in its enhanced oil recovery system under a long-term sales agreement. The Generating Facility supplies thermal energy in the form of saturated steam comprised of approximately 75% steam and 25% water. Useful thermal energy is calculated using the measured mass flow through the HRSG, measured feedwater temperature, measured steam pressure, measured steam quality, and the ASME steam tables to calculate BTU content of the steam.

(e)

Control Systems The balance of plant control system is an Emerson Ovation Distributed Control System (DCS) utilizing redundant controllers. The redundant controllers provide greater reliability by allowing continued plant operation with the loss of a control processor. Multiple operator interfaces allow the plant operator to maintain control of the turbine with the loss of an operator interface. Non-critical

Exhibit B

Generating Facility and Site Description

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

equipment may be controlled by individual Programmable Logic Controller’s (PLC) or vendor supplied controllers that interface to the balance of plant DCS. (f)

Generating Unit #1 (i)

Name: Sycamore Cogeneration Company Unit #1

(ii)

Location: Bakersfield, California

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): As of the Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the Term Start Date, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: Unknown MW. As soon as possible Seller, but no later than 30 days prior to the Term Start Date, shall provide notice to Buyer of Unit NQC (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South (ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to maintain visibility and control of the turbine with the loss of an operator interface.

Exhibit B

Generating Facility and Site Description

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(g)

Generating Unit #3 (i)

Name: Sycamore Cogeneration Company Unit #3

(ii)

Location: Bakersfield, California

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): As of the Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the Term Start Date, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: Unknown MW. As soon as possible, but no later than 30 days prior to the Term Start Date, Seller shall provide notice to Buyer of Unit NQC (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South (ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to maintain visibility and control of the turbine with the loss of an operator interface.

Exhibit B

Generating Facility and Site Description

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(h)

Single-line Diagram

Exhibit B

Generating Facility and Site Description

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(i)

Site Plan Drawing

Exhibit B

Generating Facility and Site Description

Page 5

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

2.

Site Description. (a) Sycamore Cogeneration Company Plant Site (i)

PARCEL 1. That portion of that certain patented placer mining claim known as Amazon Placer Mining Claim described in the patent as the Southwest Quarter at the Southeast Quarter of Section 30, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area, County of Kern, State of California, according to the official plat thereof, which is included within the South 10 acres of the Southwest Quarter of the South east Quarter of said Section. Except any veins or lodes of quartz or other rock in place bearing gold, silver, cinnabar, lead, tin, copper or other valuable deposits within the land above described which may have been discovered or known to exist on or prior to August 23, 1915.

(ii)

PARCEL 2. The Northwest Quarter of the Northeast Quarter of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof.

(iii)

PARCEL 3. The North Half of Lot 1 of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof.

(b)

Site Control Seller has legal control of the Site under a 1987 Ground Lease from Chevron U.S.A. (CUSA), as amended in 1987 and 2008. Seller also has easement agreements with CUSA providing for ingress and egress to the Site and all other necessary rights-of-way for operation of Seller.

(c)

Site Map

Exhibit B

Generating Facility and Site Description

Page 6

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Exhibit B

Generating Facility and Site Description

Page 7

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

*** End of Exhibit B ***

Exhibit B

Generating Facility and Site Description

Page 8

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT C [Intentionally omitted.]

*** End of Exhibit C ***

Exhibit C

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT D Monthly Contract Payment Calculation

1.

Introduction. Each Monthly Contract Payment is calculated on a calendar month basis as follows: MONTHLY CONTRACT PAYMENT, in dollars = TOD Period Energy Payment 1st TOD Period TOD Period Energy Payment 2nd TOD Period TOD Period Energy Payment 3rd TOD Period TOD Period Energy Payment 4th TOD Period TOD Period Capacity Payment 1st TOD Period TOD Period Capacity Payment 2nd TOD Period TOD Period Capacity Payment 3rd TOD Period TOD Period Capacity Payment 4th TOD Period

+ + + + + + +

All TOD Period Energy Payments shall be calculated as set forth in Section 2 of this Exhibit D. All TOD Period Capacity Payments shall be calculated as set forth in Section 3 of this Exhibit D. The “1st TOD Period,” “2nd TOD Period,” “3rd TOD Period” and “4th TOD Period” subscripts refer to the four TOD Periods that apply for the calculation month, as set forth in Section 4 of this Exhibit D. 2.

TOD Period Energy Payment Calculation. (a)

Each monthly TOD Period Energy Payment is calculated as follows: LastHour

TOD PERIOD ENERGY PAYMENT, in dollars =



[(EP-LA) x APE +

FirstHour

LA x MA] Where: EP

= TOD Period Energy Price, stated in Section 2(b) of this Exhibit D, in dollars per kWh.

APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D.

Exhibit D

Monthly Contract Payment Calculation

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D. LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. MA = Metered Amounts for each hour of the applicable TOD Period, in kWh. Metered Amounts for any hour is equal to the sum of Metered Amounts for all Metering Intervals in that hour. First Hour = First hour of the applicable TOD Period. Last Hour = Last hour of the applicable TOD Period. Once 120% of the Expected Term Year Net Energy Production is achieved, no further electric energy payments will be calculated for the remaining TOD Periods within any remaining months of the current Term Year. (b)

Factor “EP” in Section 2(a) of this Exhibit D. The TOD Period Energy Price, in dollars per kWh, for any TOD Period shall be calculated pursuant to and as determined by the methodology set forth in Exhibit S.

(c)

Factor “APE” in Section 2(a) of this Exhibit D. The Allowed Payment Energy for each hour of each TOD Period of any month is calculated as follows: APE = The sum of the Metered Energy when Buyer is Scheduling Coordinator or Scheduled Amounts when Buyer is not Scheduling Coordinator from the Generating Facility for each hour of the TOD Period, in kWh.

3.

TOD Period Capacity Payment Calculation. (a)

Each monthly TOD Period Capacity Payment is calculated on a calendar month basis as follows: TOD PERIOD CAPACITY PAYMENT in dollars = (ACP + FCP) x CAF Where: ACP =

As-Available Capacity Payment for the TOD Period, as determined in accordance with Section 3(b) of this Exhibit D, in dollars per year.

FCP =

Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(g) of this Exhibit D, in dollars per year.

CAF =

The CPUC approved Capacity Payment Allocation Factor for the TOD Period in the year, based upon the formula adopted by the CPUC in D.01-03-067:

Exhibit D

Monthly Contract Payment Calculation

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Season Summer

Winter

(b)

Capacity Payment Allocation Factors TOD Period On-Peak Period Mid-Peak Off-Peak Mid-Peak Off-Peak Super-Off-Peak

Factor 0.1792 0.0310 0.0006 0.0178 0.0011 0.0007

Factor “ACP” in Section 3(a) of this Exhibit D. The As-Available Capacity Payment shall be calculated pursuant to the following formula: AS-AVAILABLE CAPACITY PAYMENT, in dollars = AAC x AACP Where: AAC = As-Available Capacity for the TOD Period, as determined in accordance with Section 3(c) of this Exhibit D, in kWh per hour. AACP= The As-Available Capacity Price adopted by the CPUC in the Decision for the applicable year as set forth in the following table: Year 2012 2013 2014 2015

(c)

As-Available Capacity Price Price $/kW-yr 43.09 45.00 46.97 48.98

Factor “AAC” in Section 3(b) of this Exhibit D. The As-Available Capacity for each TOD Period of each month is calculated as follows: AS-AVAILABLE CAPACITY, in kWh per hour = MAC – FCC (but not less than zero) Where: MAC = The Maximum Allowed Capacity for the TOD Period as determined in Section 3(d) in this Exhibit D, in kWh per hour. FCC = The Firm Contract Capacity for all TOD Periods during a month.

(d)

Factor “MAC” in Section 3(c) of this Exhibit D. The Maximum Allowed Capacity for each monthly TOD Period is calculated as follows: MAXIMUM ALLOWED CAPACITY, in kWh per hour

Exhibit D

= LE / PH

Monthly Contract Payment Calculation

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Where: LE

= The sum of the Limited TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(e) of this Exhibit D, in kWh.

PH = The total number of hours in the TOD Period (period hours). (e)

Factor “LE” in Section 3(d) of this Exhibit D. The Limited TOD Energy for each TOD Period of any month is calculated as follows: LastHour

LIMITED TOD ENERGY, in kWh =



(E)Hour

FirstHour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour, in kWh; and (ii) Allowed Hourly Energy, as determined in Section 3(f) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (f)

Factor “E” in Section 3(e) of this Exhibit D. The Allowed Hourly Energy is calculated as follows: ALLOWED HOURLY ENERGY in kWh

= 1 hour x NCC

Where: NCC = The Net Contract Capacity, as set forth in Section 1.02(d), in kW. (g)

Factor “FCP” in Section 3(a) of this Exhibit D. Each monthly Firm Capacity Payment is calculated as follows: FIRM CAPACITY PAYMENT in dollars = MFCP x AF Where: MFCP = Maximum Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(h) of this Exhibit D, in dollars.

Exhibit D

Monthly Contract Payment Calculation

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

AF

= (i) (ii)

One (1), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is greater than or equal to 95%; or Zero (0), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is less than 60%; or

(iii) If neither (i) nor (ii) are true, then AF is the Availability Penalty Factor, as calculated in Section 3(n) of this Exhibit D. (h)

Factor “MFCP” in Section 3(g) of this Exhibit D. The Maximum Firm Capacity Payment for each TOD Period of each month is calculated as follows: MAXIMUM FIRM CAPACITY PAYMENT, in dollars = FCC x CP Where: FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d), in kWh per hour. CP

(i)

= Firm Capacity Price, as set forth in Section 1.06(a), in $/kW-year.

Factor “ACF” in Section 3(g) of this Exhibit D. The Availability Credit Factor for each monthly TOD Period is calculated as follows: AVAILABILITY CREDIT FACTOR

= (ECH + CCH) / PH

Where: ECH = The total number of Earned Capacity Hours, determined in accordance with Section 3(j) of this Exhibit D. CCH = The total number of Capacity Credit Hours, determined in accordance with Section 3(m) of this Exhibit D. PH = The total number of hours in the TOD Period (period hours). (j)

Factor “ECH” in Section 3(i) of this Exhibit D. The Earned Capacity Hours for each monthly TOD Period is calculated as follows: EARNED CAPACITY HOURS

=

FE / FCC

Where: FE

= The sum of the Firm TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(k) of this Exhibit D, in kWh.

Exhibit D

Monthly Contract Payment Calculation

Page 5

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d) in kWh per hour. (k)

Factor “FE” in Section 3(j) of this Exhibit D. The Firm TOD Energy for each TOD Period of any month is calculated as follows: LastHour

FIRM TOD ENERGY in kWh



=

(E)Hour

FirstHour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour in kWh; and (ii) Allowed Firm Energy, as determined in Section 3(l) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (l)

Factor “E” in Section 3(k) of this Exhibit D. The Allowed Firm Energy is calculated as follows: ALLOWED FIRM ENERGY in kWh

= 1 hour x FCC

Where: FCC = The Firm Contract Capacity set forth in Section 1.02(d). (m)

Factor “CCH” in Section 3(i) of this Exhibit D. The total number of Capacity Credit Hours for each monthly TOD Period is determined as follows: CAPACITY CREDIT HOURS

= TCV + FCV + MCV

Where: TCV = The total Transmission Curtailment Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-2, when the Metered Energy was curtailed by either the CAISO or the Transmission Provider. FCV = The total Force Majeure Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-1, when the

Exhibit D

Monthly Contract Payment Calculation

Page 6

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Metered Energy was curtailed by a Force Majeure event claimed by Buyer to the extent the Generating Facility is otherwise available. MCV = The total Maintenance Credit Value during the TOD Period, determined in accordance with Section 9 of Exhibit E. (n)

Factor “APF” in Section 3(g) of this Exhibit D. The Availability Penalty Factor for each monthly TOD Period is calculated as follows: AVAILABILITY PENALTY FACTOR = 1.0 – 2.0 x (CR – ACF) Where: APF = The greater of: (i) zero; and (ii) the result of the above equation for APF. CR = 95%, the minimum Capacity Performance Requirement. ACF = The Availability Credit Factor determined in accordance with Section 3(i) of this Exhibit D.

4.

Time of Delivery Periods. TOD Period On-Peak

Summer Jun 1st – Sep 30th Noon – 6:00 p.m.

Winter Oct 1st – May 31st Not Applicable.

8:00 a.m. – Noon

Applicable Days Weekdays except Holidays. Weekdays except Holidays.

Mid-Peak

8:00 a.m. - 9:00 p.m. 6:00 p.m. – 11:00 p.m.

Weekdays except Holidays. 6:00 a.m. – 8:00 a.m.

Weekdays except Holidays.

9:00 p.m. – Midnight

Weekdays except Holidays.

Midnight – Midnight

6:00 a.m. – Midnight

Weekends and Holidays.

Not Applicable.

Midnight – 6:00 a.m.

Weekdays, Weekends and Holidays.

11:00 p.m. – 8:00 a.m. Off-Peak

Super-Off-Peak

“Holiday”, as used in the above table, means New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. When a Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. *** End of Exhibit D ***

Exhibit D

Monthly Contract Payment Calculation

Page 7

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT D-1 Force Majeure Credit Value 1.

Overview. This Exhibit D-1 describes the methodology for computing Force Majeure Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Force Majeure Credit Value. For every period of Force Majeure curtailment requested by Buyer, Buyer shall compute the Force Majeure Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-1, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the Force Majeure event and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of Benchmark Capacity minus Hourly Power Output or zero In case of division by zero, the value being calculated shall be zero.

Exhibit D-1

Force Majeure Credit Value

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Force Majeure Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Force Majeure Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. *** End of Exhibit D-1 ***

Exhibit D-1

Force Majeure Credit Value

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT D-2 Transmission Curtailment Credit Value 1.

Overview. This Exhibit D-2 describes the methodology for computing Transmission Curtailment Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Transmission Curtailment Credit Value. For every period of curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, Buyer shall compute the Transmission Curtailment Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-2, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the curtailment notification and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of: Benchmark Capacity minus Hourly Power Output or zero In case of division by zero, the value being calculated shall be zero.

Exhibit D-2

Transmission Curtailment Credit Value

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Transmission Curtailment Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Transmission Curtailment Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. ______________________________________________________________________________ *** End of Exhibit D-2 ***

Exhibit D-2

Transmission Curtailment Credit Value

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT E Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits 1.

Overview. Seller shall follow the protocols established in this Exhibit E for the scheduling of Maintenance Outages and Major Overhauls, and for any subsequent notification that may be required to update a previously scheduled Maintenance Outage or Major Overhaul for which Seller wishes to obtain Maintenance Credit Value. This Exhibit E also describes the methodology for computing Maintenance Credit Value and Maintenance Debit Value.

2.

Notification. Seller shall direct all Maintenance Outage and Major Overhaul notifications to Buyer’s web-based outage scheduling system or an e-mail address designated by Buyer (the “Web Scheduler”) and to the Generation Operations Center, whose URL and telephone number(s) can be found in Exhibit N.

3.

Scheduling. (a)

Seller shall schedule all Maintenance Outages and Major Overhauls with Buyer in advance. Seller’s failure to schedule an unplanned outage in advance is not a default under this Agreement. The notice requirements for Maintenance Outages and Major Overhauls are as follows: Outage Duration Maintenance Outage, Less than 1 day Maintenance Outage, 1 day or more Major Overhaul

(b)

Exhibit E

Minimum Advance Notice 24 Hours 168 Hours 6 Months

Seller shall provide the following information when scheduling a Maintenance Outage or a Major Overhaul via the Web Scheduler: (i)

The identification number set forth on the cover page of this Agreement;

(ii)

Password (supplied by Buyer);

(iii)

Generating Unit Number*;

(iv)

Capacity Credit Period, including: (1)

The date and time when Seller expects the Capacity Credit Period to begin, and

(2)

The date and time when Seller expects the Capacity Credit Period to end.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(v)

“Scheduled Power Offline”**, in kW, is the Hourly Power Output that is expected to be offline during each hour of the outage period, as such may be updated as set forth in this Exhibit E; and

(vi)

Reason for the requested Maintenance Outage or Major Overhaul.

*Unit designation is applicable only when the contract calls for separate tracking of outage allowance for each Generating Unit. **If unit designation is applicable, Seller must provide the expected Scheduled Power Offline of the Generating Unit scheduled for maintenance; otherwise, Seller must provide the expected Scheduled Power Offline of the Generating Facility. 4.

Rescheduling. (a)

A Maintenance Outage and the associated Capacity Credit Period may be rescheduled if Seller’s request to reschedule is received by Buyer no later than 5:00 p.m. PPT on the day before the Maintenance Outage was previously scheduled to begin.

(b)

A Major Overhaul and the associated Capacity Credit Period may be rescheduled provided:

(c) 5.

(i)

The rescheduled Major Overhaul begins six months or more after the first outage notification date and time;

(ii)

The notification to reschedule is made at least one week before the Major Overhaul was previously scheduled to begin; and

(iii)

There is at least a one-month period between the notification to reschedule and the commencement of the rescheduled Major Overhaul.

Maintenance Outages and Major Overhauls may be rescheduled more than once.

Extension. (a)

Seller may extend a Maintenance Outage or a Major Overhaul and the associated Capacity Credit Period by notifying Buyer of the extension no later than 5:00 p.m. PPT on the day before the outage was previously scheduled to end. Seller’s failure to provide such notice, to the extent resulting from unexpected circumstances, is not a default under this Agreement.

(b)

Maintenance Outages and Major Overhauls and the associated Capacity Credit Periods may be extended more than once.

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(c)

For a Maintenance Outage and the associated Capacity Credit Period which is less than 24 hours in duration, the extension cannot result in a total outage duration greater than 23 hours.

6.

Cancellation. If Seller cancels a scheduled Maintenance Outage, Major Overhaul or the associated Capacity Credit Period, a cancellation notice must be received by Buyer no later than 5:00 p.m. PPT on the day before such Maintenance Outage or Major Overhaul was scheduled to begin.

7.

Updating Scheduled Power Offline.

8.

9.

(a)

If a change in the Hourly Power Output is anticipated or occurs during a Maintenance Outage or a Major Overhaul, the Scheduled Power Offline must be updated on a prospective basis as soon as possible via the Web Scheduler. Scheduled Power Offline cannot be updated once the Maintenance Outage or Major Overhaul is over.

(b)

Multiple updates to the Scheduled Power Offline can be submitted if necessary on a prospective basis.

(c)

If a Maintenance Outage or a Major Overhaul is completed ahead of schedule and Seller’s Hourly Power Output has returned to normal output levels earlier than expected, Seller shall advise Buyer of the situation by providing an update to the Scheduled Power Offline as described in Section 7(a) of this Exhibit E.

Restrictions. (a)

Seller shall make reasonable efforts not to schedule a Maintenance Outage or Major Overhaul during the Peak Months. Should an outage be required during the said period, Seller shall abide by the limit as set forth in Section 1.05(d) for minor maintenance work during peak months.

(b)

Each Capacity Credit Period must be scheduled to start and stop at the beginning of an hour. Also, when scheduling an outage, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

(c)

Seller may not schedule a Maintenance Outage or a Major Overhaul that overlaps another Maintenance Outage, Major Overhaul, or Curtailment Period already scheduled on the Generating Facility. If unit designation is applicable in Section 3(b)(iii) of this Exhibit E, this restriction applies to the Generating Unit.

Maintenance Credit Calculation. For every properly scheduled Maintenance Outage and Major Overhaul, to the extent there is an associated Capacity Credit Period, Buyer shall

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

compute and apply the associated Maintenance Credit Value and the Maintenance Debit Value following these steps: (a)

A Benchmark Capacity shall be determined for every scheduled Maintenance Outage and Major Overhaul. For purposes of this Exhibit E, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, at or after the time of outage notification, and before the start of the outage. If the outage is rescheduled, the most recent notification time shall be used in defining Benchmark Capacity. If the outage is extended, or its Scheduled Power Offline is updated, the original notification time shall be used in defining Benchmark Capacity, unless the outage has been rescheduled before the extension, in which case the most recent rescheduling notification time shall be used in defining Benchmark Capacity. In the special case of a less-than-one-day Maintenance Outage that directly follows another less-than-one-day Maintenance Outage, Benchmark Capacity of the outage that follows is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, between these two outage time periods. In the event of back-to-back, less-than-one-day Maintenance Outages, Benchmark Capacity for the second outage shall be zero. Notwithstanding this Section 9(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Capacity Credit Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during such Capacity Credit Period.

(b)

For each hour in the Capacity Credit Period of the Maintenance Outage or the Major Overhaul, an Hourly Credit Value and Hourly Debit Value shall be calculated using following formulas: (i)

Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the lesser of Benchmark Capacity minus Hourly Power Output, or Scheduled Power Offline. However, in all cases, Delta shall never be less than zero.

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(ii)

Hourly Debit Value = (Scheduled Power Offline / Firm Contract Capacity) * 1 hour

(c)

For each hour in the Capacity Credit Period, the Hourly Credit Value shall be applied as Maintenance Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Capacity Credit Period have been applied, or until the condition described in Section 9(d) of this Exhibit E is met, whichever comes first.

(d)

Simultaneous to Section 9(c) of this Exhibit E, for each hour in the Capacity Credit Period, the Hourly Debit Value shall be accumulated as Maintenance Debit Value in a Term-Year-to-date account whose increasing total is to be compared to the appropriate limit set forth in Sections 1.05(a) or (b). Once the Term-Year-todate total reaches or exceeds the limit, no more Hourly Credit Values shall be applied.

(e)

After all the Hourly Credit Values have been applied and the Hourly Debit Values accounted for, the final monthly Maintenance Credit Value and the Term-Year-todate cumulative Maintenance Debit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision.

The above description of the evaluation process assumes that the outage was properly scheduled with sufficient advance notice pursuant to this Exhibit E and was approved by Buyer (or the CAISO, if applicable). Any deviation from the proper scheduling protocol can result in reduced Maintenance Credit Value or increased Maintenance Debit Value. *** End of Exhibit E ***

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 5

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT F [Intentionally omitted.] *** End of Exhibit F ***

Exhibit F

[Intentionally omitted.] Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT G Scheduling Coordinator Services This Exhibit G is only applicable when Buyer is Scheduling Coordinator. 1.

2.

Designation of Buyer as Scheduling Coordinator. (a)

At least 30 days before the Term Start Date, Seller shall take all actions and execute and deliver to Buyer and the CAISO all documents necessary to authorize or designate Buyer as Scheduling Coordinator with the CAISO effective as of the Term Start Date.

(b)

During the Term, unless Seller terminates Buyer as Scheduling Coordinator in accordance with Section 7 of this Exhibit G, Seller may not authorize or designate any other party to act as Scheduling Coordinator, nor shall Seller perform for its own benefit the duties of Scheduling Coordinator, and Seller may not revoke Buyer’s authorization to act as Scheduling Coordinator unless agreed to by Buyer.

(c)

Buyer shall submit bids and schedules to the CAISO in accordance with the CAISO Tariff and Seller’s QF PGA or PGA, as applicable.

(d)

Buyer shall submit all required notices and updates regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO in accordance with the CAISO procedures.

(e)

Seller is not entitled to any Monthly Capacity Payment until Buyer is fully authorized as Scheduling Coordinator for the Generating Facility; provided, however, that Buyer may not take, or not refrain from taking, any action if the result would be to delay such authorization.

Buyer’s Scheduling Responsibilities. Pursuant to the CAISO Tariff, Buyer shall be responsible for the following: (a)

Using the Forecast submitted by Seller to Buyer pursuant to Exhibit I, including updated Forecasts to the extent reasonably practicable, to forecast Seller’s expected generation using Buyer’s forecasting model (“Buyer Projected Energy Forecast”) in any given hour;

(b)

Adjusting Buyer Projected Energy Forecast for forecasted electric energy line losses in accordance with the amount of electric energy Seller is expected to deliver to the Delivery Point;

(c)

Submitting the adjusted Forecasts to the CAISO as Scheduling Coordinator Schedules (as defined in the CAISO Tariff); and

Exhibit G

Scheduling Coordinator Services

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(d)

Receiving notification of the final schedules from the CAISO.

3.

Notices. As Scheduling Coordinator, Buyer shall submit all notices and updates required under the CAISO Tariff and Applicable Laws regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO, including all SLIC Outage requests, SLIC Forced Outages, CAISO Forced Outage Reports, or must offer waiver forms.

4.

Scheduling Fees. In accordance with Section 4.02, Buyer shall invoice to Seller and Seller shall pay to Buyer the following Scheduling Fees: (a)

SC Set-Up Fee. The SC Set-Up Fee is equal to the costs Buyer incurs as a result of the Generating Units or the Generating Facility registration, as applicable, as well as installation, configuration, and testing of all equipment and software necessary, in Buyer’s sole discretion, to Schedule the Generating Unit or the Generating Facility, as applicable, in accordance with the CAISO Tariff. Buyer’s invoice to Seller shall provide a detailed accounting of all costs and charges encompassed in the SC Set-Up Fee, including separate line items for registration charges, equipment costs, software costs, and labor costs (including hourly rate if applicable) itemized for registration, equipment installation, configuration, testing and software related charges. Buyer estimates that the SC Set-up Fee for this Agreement will equal $1,450.

(b)

Monthly Scheduling Fee. The Monthly Scheduling Fee will be as forth in the following table.

Net Contract Capacity (kW)

Monthly Scheduling Fee

Less than 10,000

$2,500

10,000 – 100,000

$5,000

Greater than 100,000

$7,500

5. CAISO Settlements. As Scheduling Coordinator, Buyer shall be responsible for all settlement functions with the CAISO related to the Generating Units or the Generating Facility, as applicable. Seller shall cooperate with Buyer in Buyer’s performance of any settlement functions, and Seller shall promptly deliver to Buyer, or provide Buyer access to, all Generating Unit or the Generating Facility, as applicable, data necessary for CAISO settlements and any correspondence or communications with CAISO related to the Generating Units or the Generating Facility, as applicable, including any invoices or settlement data, in the mutually agreed upon format reasonably requested by Buyer.

Exhibit G

Scheduling Coordinator Services

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Buyer shall render a separate invoice to Seller for all CAISO Charges for which Seller is responsible under this Agreement (“CAISO Charges Invoice”) as described in Sections 1 through 4 of Exhibit J, in accordance with the applicable billing and payment methodologies utilized for the specific CAISO Charge as set forth in the CAISO Tariff. CAISO Charges Invoices shall be rendered after final settlement information becomes available from the CAISO that identifies any CAISO Charges. At Seller’s request, Buyer shall provide Seller with an invoice detailing all Generating Facility CAISO Charges by individual CAISO Charge codes or types used by CAISO to identify individual CAISO Charges including a copy of all supplemental or supporting documentation provided by the CAISO to Buyer in the settlement process. Seller shall pay the amount of CAISO Charges Invoices on or before the later of the 20th day of each month, or tenth day after receipt of the CAISO Charges Invoice or, if such day is not a Business Day, then on the next Business Day. If Seller fails to pay a CAISO Charges Invoice within such timeframe, Buyer may offset any amounts owing to it for these CAISO Charges Invoices as set forth in Section 4.02. 6.

Disputes and Adjustments of CAISO Invoices. The Parties agree that all CAISO Charges Invoices are subject to the CAISO Tariff and may be adjusted by the CAISO, or disputed by Buyer, as Scheduling Coordinator, in accordance with the CAISO Tariff. The Parties agree that all CAISO Charges Invoices are subject to dispute between the Parties in accordance with this Agreement. Notwithstanding anything to the contrary contained in this Agreement, the Parties agree that the obligations under this Exhibit G with respect to the payment of CAISO Charges Invoices, or the adjustment of such CAISO Charges Invoices, shall survive the expiration or termination of this Agreement for a period of 365 days beyond the time period which CAISO may adjust, modify or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the CAISO Tariff.

7.

Terminating Buyer’s Designation as Scheduling Coordinator. (a)

Seller may terminate Buyer as Scheduling Coordinator: (i)

In accordance with Section 7(b) of this Exhibit G; or

(ii)

If Buyer materially fails to fulfill its obligations as Scheduling Coordinator and: (1)

Seller provides advance Notice to Buyer setting forth in reasonable detail the nature of such failure and such failure is not remedied within 30 days after such Notice; provided, however, that if such failure is not reasonably capable of being remedied within such 30day period, Buyer shall have such additional time (not to exceed 120 days) as is reasonably necessary to remedy such failure, so

Exhibit G

Scheduling Coordinator Services

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

long as Buyer promptly commences and diligently pursues such remedy;

(iii)

(b)

(2)

Seller (A) submits to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the date of Buyer’s termination as Scheduling Coordinator, and (B) causes its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

(3)

The Parties will take any other action necessary to terminate the designation of Buyer as Scheduling Coordinator, including amending this Agreement; or

If Seller is required to elect Buyer as Scheduling Coordinator in accordance with Section 1.08, then, subject to Section 3.06(b) or 3.09(b), as applicable, by (1) providing a Notice to Buyer on or before the 60th day after Seller meets the requirements of Section 3.06(a) and 3.09(a), and (2) at least 30 days before the replacement Buyer as the Scheduling Coordinator, complying with the requirements for designating a different Scheduling Coordinator by taking all necessary actions to terminate the designation of Buyer as Scheduling Coordinator, including those actions set forth in Sections 7(b)(i) and (b)(ii) of this Exhibit G. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator.

At least 30 days before the expiration of the Term or as soon as an Early Termination Date is declared (regardless of which Party declared it), the Parties will take all actions necessary to terminate the designation of Buyer as Scheduling Coordinator as of 11:59 p.m. PPT on the Term End Date (“SC Replacement Date”). Such actions include the following: (i)

(ii)

Seller shall: (1)

Submit to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the SC Replacement Date; and

(2)

Cause its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

Buyer shall submit a letter to the CAISO resigning as Scheduling Coordinator effective as of the SC Replacement Date.

Exhibit G

Scheduling Coordinator Services

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(c)

Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator. *** End of Exhibit G ***

Exhibit G

Scheduling Coordinator Services

Page 5

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT H [Intentionally omitted.] *** End of Exhibit H ***

Exhibit H

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT I Seller’s Forecasting Submittal and Accuracy Requirements 1.

2.

General Requirements. The Parties shall abide by the Forecasting requirements and procedures described below and shall agree upon reasonable changes to these requirements and procedures from time to time as necessary to: (a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the Operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated Forecast and outage submissions.

Seller’s Forecasting Submittal Requirements for all Generating Facilities. (a)

30-Day Forecast. No later than 30 days before the Term Start Date, Seller shall provide Buyer with a Forecast for the 30-day period commencing on the start of the Term using the Web Client. If the Web Client becomes unavailable, Seller shall provide Buyer with the Forecast by e-mail or by telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N. The Forecast, and any updated Forecasts provided pursuant to this Section 2, shall:

(b)

Exhibit I

(i)

Not include any anticipated or expected electric energy losses between the CAISO-Approved Meter and the Delivery Point; and

(ii)

Limit hour-to-hour Forecast changes to no less than 250 kWh during any period when the Web Client is unavailable. Seller shall have no restriction on hour-to-hour Forecast changes when the Web Client is available.

Weekly Update to 30-Day Forecast. Commencing on or before 5:00 p.m. PPT of the Wednesday before the first week covered by the Forecast provided pursuant to Section 2(a) of this Exhibit I, and on or before 5:00 p.m. PPT every Wednesday thereafter until the Term End Date, Seller shall update the Forecast for the 30-day period commencing on the Sunday following the weekly Wednesday Forecast update submission. Seller shall use the Web Client, if available, to supply this weekly update or, if the Web Client is not available, Seller shall provide Buyer with the weekly Forecast update by e-mailing or telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N.

Seller’s Forecasting Submittal and Accuracy Requirements

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(c)

Further Update to 30-Day Forecast. As soon as reasonably practicable and commensurate with Seller’s knowledge, Seller shall provide Forecast updates related to Buyer’s Scheduled daily, hourly and real-time deliveries from the Generating Facility for any cause, including changes in Site ambient conditions, a Forced Outage, or a Real-Time Forced Outage, any of which results in a material change to the Generating Facility’s deliveries (whether in part or in whole). This updated Forecast pursuant to this Exhibit I must be submitted to Buyer via the Web Client by no later than: (i)

5:00 p.m. PPT on the day before the Trading Day impacted by the change, if the change is known to Seller at that time;

(ii)

The Hour-Ahead Scheduling Deadline, if the change is known to Seller at that time; or

(iii) If the change is not known to Seller by the timeframes indicated in (i) or (ii) immediately above, no later than 20 minutes after Seller becomes aware of the event which caused the expected electric energy production change. Seller’s updated Forecast must contain the following information: (w) The beginning date and time of the event resulting in the availability of the Generating Facility and expected electric energy production change;

3.

(x)

The expected ending date and time of the event:

(y)

The expected electric energy production, in MWh; and

(z)

Any other information required by the CAISO as communicated to Seller by Buyer.

Seller’s Forecasting Accuracy Requirements. If a (non-zero) Firm Contract Capacity quantity is applicable to this Agreement, then this Section 3 applies to Seller. (a)

Accuracy Metric. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate and report to Seller the monthly mean absolute error (“MAEm”) between Seller’s Day-Ahead Forecasts and the respective daily summations of Metered Energy: Forecast Error MAEm = Total Forecast

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company n

Forecast Error =



| fi – ai |

i

n

Total Forecast =

 fi i

where: n

= the total number of hours in calendar month “m”

i

= an hour within month “m”

fi = Seller’s Day-Ahead Forecast for hour “i” ai = the quantity of (i) Metered Energy for hour “i” plus the quantity of electric energy not delivered as a result of a Real-Time Forced Outage for hour “i” (in MWh) when the Generating Facility is not PIRP-eligible, or when Buyer is not Scheduling Coordinator; or (ii) the actual available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator. Buyer shall report each MAEm to Seller and, upon Seller’s request, Buyer shall furnish all supporting calculations within a reasonable timeframe. Notwithstanding anything to the contrary set forth in this Section 3(a), for hour “i” for which the absolute difference between variable “fi” and variable “ai” is a number greater than zero, to the extent that such difference results from the fault or negligence of Buyer in its role as Scheduling Coordinator the value “| fi – ai |” for that hour shall be deemed to be zero. (b) Forecasting Penalty. If the MAEm for a particular month “m” is greater than 15% or if the average Forecast error for all hours of the month is greater than three MW, then an “MAE Failure” will be deemed to have occurred. An MAE Failure will be waived if Seller demonstrates to Buyer’s reasonable satisfaction that the MAE Failure was the result of unexpected changes in either electrical or steam demand associated with the Site Host Load. If such MAE Failure has been waived, then that month does not count as a month in which there was an MAE Failure. For each month in which an MAE Failure has occurred, Seller shall pay a fee equal to the applicable Monthly Scheduling Fee in addition to any otherwise applicable Monthly Scheduling Fee. During each month an MAE Failure occurs, subject to the limitations of the following paragraph, Seller will continue to receive Monthly Capacity Payments for the Firm Contract Capacity based on the Firm Capacity Price and capacity payment calculations for firm capacity as set forth in Section 3 of Exhibit D.

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

If, however, an MAE Failure occurs three times in any rolling 12-month period, then starting on the first day of the calendar month immediately following the third such occurrence (such month, the “First Penalty Month”): (i)

The quantity of Firm Contract Capacity specified in Section 1.02(d) will be deemed to be zero (“Penalized Firm Contract Capacity”); and

(ii)

The quantity of As-Available Contract Capacity specified in Section 1.02(d) will be deemed increased by the quantity of Firm Contract Capacity as such quantity existed before the First Penalty Month (“Penalized As-Available Contract Capacity”).

The Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall continue to be in effect during every subsequent calendar month until there are two consecutive calendar months without an MAE Failure (including a month in which an MAE Failure has been waived). Upon such event, starting on the first day of the calendar month immediately following the second consecutive month during which Buyer does not have an MAE Failure, the Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall revert to the Firm Contract Capacity and AsAvailable Contract Capacity quantities existing before the First Penalty Month. *** End of Exhibit I ***

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT J CAISO Charges If at any time after the Term Start Date Buyer is not Scheduling Coordinator for the Generating Facility, then Buyer will not be responsible for any CAISO Charges. If at any time after the Term Start Date Buyer is Scheduling Coordinator for the Generating Facility, then Buyer shall pay all CAISO Charges and receive all CAISO Revenues; provided, however, if at any time after the Term Start Date: 1.

The CAISO implements or has implemented any sanction or penalty related to Scheduling, outage reporting or generator Operation, and any such sanctions or penalties are imposed on the Generating Facility or to Buyer as Scheduling Coordinator for the Generating Facility due solely to the actions or inactions of Seller, then such sanctions or penalties will be Seller’s responsibility;

2.

Seller or any third party dispatches any portion of the Net Contract Capacity for the benefit of any party other than Buyer or a Site host in respect of the Host Site, then Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator);

3.

Seller does not comply with: (a)

The requirements set forth in Section 3.15; or

(b)

Seller’s obligation associated with any CAISO or Transmission Provider notice or instruction (as may be communicated by Buyer as Scheduling Coordinator) to (i) increase output to the Firm Contract Capacity during a System Emergency or an Emergency Condition, or (ii) reschedule a planned outage set to occur during a System Emergency or an Emergency Condition, then

Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges associated with any failure set forth in Sections 3(a) or 3(b) of this Exhibit J (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator); or 4.

If the Generating Facility is PIRP-eligible and is not certified as a PIRP resource for any reason, then Seller shall indemnify, defend, and hold Buyer harmless against all CAISO Charges associated with the electric energy generated and delivered from the Generating Facility.

If any of Sections 1 through 4 of this Exhibit J apply and the Generating Facility is subject to an Uninstructed Deviation Penalty, Seller will not be required to pay the SDD Energy Adjustment and, instead, shall be responsible for all applicable Uninstructed Deviation Penalty charges for the Generating Facility. *** End of Exhibit J ***

Exhibit J

CASIO Charges

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT K Scheduling and Delivery Deviation Adjustments If Buyer is Scheduling Coordinator for the Generating Facility and if the Generating Facility is not PIRP-eligible, then Seller or Buyer, as the case may be, shall be responsible for the following SDD Adjustments with respect to the Generating Facility: 1.

SDD Energy Adjustment. An Adjustment will be calculated for each Settlement Interval in a month if the Metered Energy is either (a) less than the Performance Tolerance Band Lower Limit in any Settlement Interval or (b) greater than the Performance Tolerance Band Upper Limit in any Settlement Interval. When the SDD Energy Adjustment is negative, Seller shall make a payment to Buyer and when the SDD Energy Adjustment is positive, Seller shall receive a credit from Buyer. The SDD Energy Adjustment is calculated as follows: If A < D, then SDD Energy Adjustment= (D – A) x (EP – P) or If A > E, then SDD Energy Adjustment = (A – E) x (P – EP) Otherwise, the SDD Energy Adjustment = 0 where: A = Metered Energy for the Settlement Interval; B = Seller’s Final Energy Forecast based on the hourly forecasts made pursuant to Exhibit I corresponding to the Settlement Interval; C = Performance Tolerance Band = The greater of (a) three percent of the Seller’s Final Energy Forecast divided by the number of Settlement Intervals in such hour or (b) one (1) MWh divided by the number of Settlement Intervals in such hour; D = Performance Tolerance Band Lower Limit = (B – C); E = Performance Tolerance Band Upper Limit = (B + C); EP =

TOD Period Energy Price applicable to the Settlement Interval specified in Section 2(b) of Exhibit D; and

P = Real-Time Price for the Generator’s PNode as published by the CAISO on OASIS for the Settlement Interval.

Exhibit K

Scheduling and Delivery Deviation Adjustments

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

2.

SDD Administrative Charge. Seller shall make a payment to Buyer (the “SDD Administrative Charge”) for each Settlement Interval in a month if Metered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, in any Settlement Interval. The SDD Administrative Charge is calculated as follows: If A > (B + C) or A < (B – C), then: SDD Administrative Charge = (Absolute Value (B – A) – C) x Uninstructed Deviation GMC Rate. Otherwise, the SDD Administrative Charge = 0. *** End of Exhibit K ***

Exhibit K

Scheduling and Delivery Deviation Adjustments

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT L Physical Trade Settlement Amount This Exhibit L is only applicable when Buyer is not Scheduling Coordinator. 1.

Physical Trades Cleared in the IFM. The CAISO Revenue credited to Buyer’s account by CAISO as a result of a Physical Trade having cleared in the IFM shall be for Buyer’s account.

2.

Physical Trades not Cleared in the IFM. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate the Physical Trade Settlement Amount (“PTSAi”) for each hour as follows: PTSAi =

CPTi x (CPTPi – PNodei)

Where: i

=

an hour within month “m”

CPT

=

Converted Physical Trade, in MWh

CPTP

=

Converted Physical Trade Price, and

PNode

=

the Generating Facility’s PNode price, in dollars per MWh.

If the PTSAi is positive and Seller submitted the original Physical Trade in accordance with Section 3.14(s)(ii) and Exhibit I, then Buyer shall owe Seller the PTSAm for month m. In any event the PTSAi is negative, however, then Seller shall owe Buyer the PTSAi. *** End of Exhibit L ***

Exhibit L

Physical Trade Settlement Amount

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT M SC Trade Settlement Amount This Exhibit M is only applicable when Buyer is not Scheduling Coordinator. If, in any Settlement Interval, a Generating Facility’s Scheduled Amount differs from the Generating Facility’s Metered Energy by more than the SC Trade Tolerance Band, then Seller shall be subject to a payment adjustment calculated by Buyer in accordance with the procedures and formulas set forth below. (1)

Under-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy, and the Real-Time Price is greater than the DayAhead Price payable during the Settlement Interval, then Seller’s monthly payment amount shall be reduced by each Under-Scheduling Settlement Interval Adjustment Amount calculated by the following formula: UNDER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [A – B] x [D – C] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No under-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy if, during such Settlement Interval, the Real-Time Price is equal to or less than the Day-Ahead Price payable during the Settlement Interval. (2)

Over-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy, and the Real-Time Price is less than the DayAhead Price payable during the Settlement Interval; Then Seller’s monthly payment amount shall be reduced by each Over-Scheduling Settlement Interval Adjustment Amount calculated by the following formula:

Exhibit M

SC Trade Settlement Amount

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

OVER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [B – A] x [C – D] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No over-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy if, during such Settlement Interval, the Real-Time Price is greater than or equal to the Day-Ahead Price payable during the Settlement Interval. *** End of Exhibit M ***

Exhibit M

SC Trade Settlement Amount

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT N Notice List SYCAMORE COGENERATION COMPANY

SOUTHERN CALIFORNIA EDISON COMPANY

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

Contract Sponsor: Attn: Executive Director Street: P.O. Box 80478 City: Bakersfield, California 93380 Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected]

Contract Sponsor: Attn: Vice President of Renewable and Alternative Power Street: 2244 Walnut Grove Avenue City: Rosemead, California 91770 Phone: Facsimile:

Reference Numbers: Duns: 18-507-4887 Federal Tax ID Number: 95-4014893

Reference Numbers: Duns: 006908818 Federal Tax ID Number: 95-1240335

Contract Administration: Attn: Business Manager Phone: (661) 615-4675 Facsimile: (661) 615-4610 E-mail: [email protected]

Contract Administration: Attn: Phone: Facsimile: E-mail:

Forecasting: Attn: Control Room Phone: (661) 615-4704 Facsimile: (661) 615-4664 E-mail: [email protected]

Forecasting: Attn: Phone: 626.307.4420 Facsimile: E-mail: [email protected]

Day-Ahead Forecasting: Phone: (661) 615-4704 Facsimile: (661) 615-4664 E-mail: [email protected]

Day-Ahead Scheduling: Attn: Manager of Day-Ahead Operations Attn: Scheduling Desk Phone: 626.307.4425 or 626.307.4420 Facsimile: 626.307.4413 E-mail: [email protected]

Exhibit N

Notice List

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Real-Time Forecasting: Phone: (661) 615-4639 Facsimile: (661) 615-4610 E-mail: [email protected]

Real-Time Scheduling: Attn: Manager of Real-Time Operations Attn: Operations Desk Phone: 626.307.4405 or 626.307.4453 Facsimile: 626.307.4416 E-mail: [email protected] Payment Statements: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: CAISO Charges and CAISO Sanctions: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Payments: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Wire Transfer: BNK: JP Morgan Chase Bank ABA: 021000021 ACCT: 323-394434 Credit and Collateral: Attn: Manager of Credit and Collateral Phone: Facsimile: Email:

Payment Statements: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] CAISO Charges and CAISO Sanctions: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Payments: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Wire Transfer: BNK: Chase Manhattan ABA: 021-0000-21 ACCT: 910-2588-705 Credit and Collections: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: : (661) 615-4610 E-mail: [email protected] With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Guarantor: N/A Attn: Phone: Facsimile: E-mail:

Exhibit N

With additional Notices of an Event of Default or Potential Event of Default to: Attn: Manager SCE Law Department Power Procurement Section Phone: Facsimile: Email: Guarantor: N/A Attn: Phone: Facsimile: E-mail:

Notice List

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Lender: N/A Attn: Phone: Facsimile: E-mail:

Lender: N/A Attn: Phone: Facsimile: E-mail: *** End of Exhibit N ***

Exhibit N

Notice List

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT O [Intentionally omitted.] *** End of Exhibit O ***

Exhibit O

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT P [Intentionally omitted.] *** End of Exhibit P ***

Exhibit P

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT Q [Intentionally omitted.] *** End of Exhibit Q ***

Exhibit Q

[Intentionally omitted.]

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT R Outage Schedule Submittal Requirements 1.

General Requirements. The Parties shall abide by the Outage Schedule Submittal Requirements described below and shall agree upon reasonable changes to these requirements and procedures from time to time, as necessary to:

2.

(a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated forecast and outage submissions.

Seller’s Availability Forecasting Submittal Requirements for all Generating Facilities. Seller shall submit maintenance and planned outage schedules in accordance with the following schedule: (a)

No later than January 1st, April 1st, July 1st and October 1st of each Term Year, and at least 60 days before the Term Start Date, Seller shall submit to Buyer its schedule of proposed planned outages (“Outage Schedule”) for the subsequent twenty four-month period using a Buyer-provided web-based system or an e-mail address designated by Buyer (“Web Client”).

(b)

Seller shall provide the following information for each proposed planned outage: (i)

Start date and time;

(ii)

End date and time; and

(iii)

Capacity online, in MW, during the planned outage.

(c)

Within 20 Business Days after Buyer’s receipt of an Outage Schedule, Buyer shall notify Seller in writing of any request for changes to the Outage Schedule, and Seller shall, consistent with Prudent Electrical Practices, accommodate Buyer’s requests regarding the timing of any planned outage.

(d)

Seller shall cooperate with Buyer to arrange and coordinate all Outage Schedules with the CAISO.

Exhibit R

Outage Schedule Submittal Requirements

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(e)

In the event a condition occurs at the Generating Facility which causes Seller to revise its planned outages, Seller shall provide Notice to Buyer, using the Web Client, of such change (including, an estimate of the length of such planned outage) as required in the CAISO Tariff after the condition causing the change becomes known to Seller.

(f)

Seller shall promptly prepare and provide to Buyer upon request, using the Web Client, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code, the CAISO Tariff or any Applicable Law mandating the reporting by investor owned utilities of expected or experienced outages by electric energy generating facilities under contract to supply electric energy. *** End of Exhibit R ***

Exhibit R

Outage Schedule Submittal Requirements

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT S TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements Introduction. Subject to Section 4.04 and Exhibit D, this Exhibit S sets forth the formulas and methodology that Buyer will use in order to calculate the TOD Period Energy Price, and also sets forth Seller’s Greenhouse Gas emissions reporting requirements. 1. TOD Period Energy Price. Subject to Section 2 of this Exhibit S, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable time-period in accordance with the following formula: TOD Period Energy Price $/kWh = ((Applicable HR * BTGP/1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = The Heat Rate for the specified time-period, per the following table: Calendar Year(s) 2011 2012 January 1, 2013 through December 31, 2014 January 1, 2015 until the termination of this Agreement

Heat Rate (Btu/kWh) 8,700 8,225 8,125 Market Heat Rate

BTGP = Calendar month Burner Tip Gas Price ($/MMBtu), per the Decision and CPUC Resolution E-4246; VOM = Calendar month avoided variable O&M ($/kWh), per the Decision and CPUC Resolution E-4246; GHG Charges = All taxes, charges or fees assessed with the implementation and regulation of Greenhouse Gas emissions with respect to the Generating Facility imposed by any Governmental Authority, such as the CARB’s AB 32 Cost of Implementation Fee (as defined in Title 17 C.C.R. §95200). For example, if the charges are assessed on but not included in fuel consumption or gas costs, the Applicable HR or Burner Tip Gas Price will be used to derive the dollars per kilowatt-hour charge. On January 1, 2015 or the commencement of the First Compliance Period, the GHG Charges will equal zero in the above formula; TOU (i.e., time-of-use) = Throughout the Term, the applicable time-of-use factors are as follows:

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

On-Peak Mid-Peak Off-Peak Super Off-Peak

Summer 1.4251 see below 0.8526 N/A

Winter N/A 1.2185 see below 0.7760

Summer Mid-Peak = (Total # hours in month - (1.4251 * # of Summer On-Peak hours in month) - (0.8526 * # of Summer Off-Peak hours in month)) / # of Summer Mid-Peak hours in month Winter Off-Peak = (Total # hours in month - (1.2185 * # of Winter Mid-Peak hours in month) - (0.7760 * # of Winter Super Off Peak hours in month)) / # of Winter Off-Peak hours in month LA (i.e., hourly location adjustment, in $/kWh) = LMPQF - LMPTrading Hub Where the hourly location adjustment (i.e., LA) will be based on the hourly Day-Ahead prices and actual hourly generation by the Generating Facility for delivery to Buyer as follows: LMPQF (in $/kWh) = The hourly Day-Ahead Locational Marginal Price at the point of interconnection with the CAISO Controlled Grid associated with the Generating Facility; and LMPTrading Hub (in $/kWh) = The hourly Day-Ahead Locational Marginal Price of the trading hub where the Generating Facility is located (i.e., SP15 Existing Zone Generation Trading Hub (formerly SP15), NP15 Existing Zone Generation Trading Hub (formerly NP15), or ZP26 Existing Zone Generation Trading Hub (formerly ZP26), as applicable, or any successor thereto). 2. TOD Period Energy Price during the Floor Test Term. (a) If there is a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), then, during the Floor Test Term, the TOD Period Energy Price will be the higher of the following two formulas (the “GHG Floor Test”): (i) TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A;

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 2

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

BTGP ($/MMBtu) = As set forth above; VOM ($/kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. OR (ii) TOD Period Energy Price $/kWh = ((Applicable HR * (BTGP + GHG Allowance Price) /1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = (A) 8,225 Btu/kWh through December 31, 2012; (B) 8,125 Btu/kWh from January 1, 2013 through December 31, 2014; and (C) Actual HR from January 1, 2015 until the end of the Floor Test Term; BTGP ($/MMBtu) = As set forth above; GHG Allowance Price ($/MMBtu) = Allowance Cost ($/MT) * 117lbs of Greenhouse Gas per MMBtu / 2,204.6 lbs per MT Where: Allowance Cost ($/MT) = The cost of one Allowance, determined using the GHG Auction clearing price from the latest GHG Auction that has taken place during the calendar quarter immediately preceding the date that Buyer’s payment is due to Seller; provided, however, that if there is no GHG Auction held during the applicable time-period, then the Allowance Cost is determined in accordance with Section 2(c) of this Exhibit S; VOM ($/kWh) = As set forth above; GHG Charges ($/kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above.

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 3

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

(b) Free Allowance Reporting and Allocation. If, at any time, Buyer makes a monthly payment to Seller utilizing the GHG Floor Test formula set forth in Section 2(a)(ii) of this Exhibit S, then Buyer shall deduct from the monthly payment to Seller for the applicable month the value of the Free Allowances disclosed in and based on all Free Allowance Notices that have not already been applied to a prior payment to Seller; provided, however, that if Buyer, using reasonable efforts, is unable to process such payment adjustment for the applicable month, then Buyer shall make such payment adjustment to the next monthly payment due to Seller. For any month that Buyer utilizes the formula set forth in Section 2(a)(ii) of this Exhibit S to make a monthly payment to Seller, Buyer shall maintain a record of the value and quantity of all Free Allowances disclosed in the Free Allowance Notices, if any, and shall deduct the value of such Free Allowances to any subsequent monthly payment due to Seller where Buyer calculates such monthly payment utilizing the formula set forth in Section (2)(a)(ii) of this Exhibit S until such time that the value of all such Free Allowances are expended. In order for Buyer to make the payment adjustment set forth in the immediately preceding paragraph, Seller agrees to deliver to Buyer, within twenty (20) days of receiving any Free Allowances, a Free Allowance Notice for the applicable month, which Free Allowance Notice must include all Additional GHG Documentation. Buyer shall value any such Free Allowances using the same methodology Buyer uses in valuing the Allowance Cost, as set forth above. (c) Determining Allowance Costs under the GHG Floor Test if there is No GHG Auction. This Section 2(c) is applicable if no GHG Auction has been held during the time-period for which the Allowance Cost variable set forth in Section 2(a) of this Exhibit S is to be determined. In such an instance, publicly available indices will be used to determine the price for the applicable period. If no such indices exist, Buyer will meet with the Trade Organizations to negotiate in good faith to reach an agreement on setting the Allowance Cost variable. If, after negotiating for fifteen (15) Business Days, Buyer and the Trade Organizations have not reached an agreement on setting the Allowance Cost variable, then Buyer and the Trade Organizations shall each select, within fifteen (15) days after such failed negotiations, price quotations for the cost of one Allowance, as set forth in two (2) different Reference Market-Makers, for a total of four (4) price quotations. The Allowance Cost variable for the applicable time-period will be determined by taking the average of the four (4) price quotations so selected by Buyer and the Trade Organizations. Seller agrees and acknowledges that it shall be bound by any agreement as to the Allowance Cost variable between Buyer and the Trade Organizations, in accordance with the foregoing. (d) TOD Period Energy Price from the end of the Floor Test Term. As of end of the Floor Test Term until the termination of this Agreement, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable timeperiod in accordance with the following formula:

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 4

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A; BTGP ($/MMBtu) = As set forth above; VOM ($kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. (e) Seller’s Responsibility. Other than Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges as set forth in payment formulas above, Seller is solely responsible for all GHG Compliance Costs and all other costs associated with implementation and regulation of GHG emissions with respect to Seller or the Generating Facility. 3. Reporting Requirements. (a) From the Effective Date through the Term End Date (and for any period following the termination of this Agreement to the extent relating back to the Term), Seller shall provide to Buyer the following information (together, the “Annual GHG Reports”): (i) On or before the fifth (5th) Business Day following Seller’s timely submission to the CARB (or any other authorized Governmental Authority having jurisdiction in California) of the CARB Mandatory GHG Emissions Annual Report, or such other annual report submitted to the CARB, detailing the Greenhouse Gas emissions of the Generating Facility for the applicable calendar year (as verified by an independent third party, if applicable) (the “CARB Annual Report”), Seller shall deliver such CARB Annual Report to Buyer; and (ii) To the extent not set forth in the CARB Annual Report (or if Seller is no longer required to submit the CARB Annual Report for any reason), then Seller shall submit to Buyer, along with the CARB Annual Report (or, if Seller is no longer required to submit the CARB Annual Report for any reason, then on the sixtieth (60th) Business Day following the end of the applicable calendar year), the following information for the applicable calendar year, which, in each case, must be verifiable and of settlement quality: (1) the Useful Thermal Energy Output of the Generating Facility; and (2)

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 5

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

total fuel usage of the Generating Facility; and (3) the total amount of Greenhouse Gas emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, and the Useful Thermal Energy Output of the Generating Facility; and (4) the total electric energy produced by the Generating Facility, the electric energy used to serve the Site Host Load, and the electric energy delivered to Buyer; and (5) the number of Allowances (including Free Allowances) held or surrendered by Seller for such calendar year during any period where the TOD Period Energy Price is calculated based on the GHG Floor Test. (b) If Buyer requires any other information not delineated in Section 3(a) of this Exhibit S in order to comply with any Greenhouse Gas emissions reporting requirements adopted by the CARB or by any other Governmental Authority and imposed on Buyer (other than the information that Seller must provide in accordance with Section 3(c) of this Exhibit S), then Buyer shall promptly meet and confer with the Trade Organizations regarding such other information that Buyer requires and negotiate in good faith to reach a mutually acceptable agreement. Seller agrees and acknowledges that it shall be bound by any agreement between Buyer and the Trade Organizations, in accordance with the foregoing. (c) Buyer will review the Annual GHG Reports described in this Section 3 to determine if there is any discrepancy in the payments made by Buyer to Seller for GHG Compliance Costs during the course of the applicable calendar year. To the extent Buyer determines that there is any such discrepancy, (i) if Buyer owes Seller an additional payment for GHG Compliance Costs, then Buyer shall make such additional payment in a subsequent monthly payment to Seller under this Agreement, or (ii) if Seller owes Buyer a payment refund for GHG Compliance Costs, then Buyer shall offset such payment refund amount in a subsequent monthly payment to Seller under this Agreement. If this Agreement terminates before Buyer is able to make such additional payment for GHG Compliance Costs or offset such GHG Compliance Costs payment refund from Seller’s monthly payments, as applicable, then Buyer or Seller, as applicable, shall pay all remaining payment amounts due within the thirty- (30) day period after the termination of this Agreement. (d) To the extent that the information provided by the disclosing Party in accordance with this Section 3 is Confidential Information, the receiving Party shall treat such Confidential Information with the same degree of care that it currently treats the data and information provided by Qualifying Cogeneration Facilities under the existing Qualifying Cogeneration Facilities monitoring compliance program. 4. Market Disruption Event. Unless this Agreement has terminated, if, on or after the date that the Market Heat Rate applies to and is used in the calculation of the TOD Period Energy Price and until the termination of this Agreement, there occurs a Market Disruption Event, then the Market Heat Rate for the affected Trading Day(s) must be determined by reference to the Market Heat Rate for the first Trading Day thereafter on which no Market Disruption

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 6

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

Event exists; provided, however, that if the Market Heat Rate is not so determined within five (5) Trading Days after the Market Disruption Event occurred or existed, then Buyer shall meet with the Trade Organizations to negotiate in good faith to reach an agreement on a Market Heat Rate (or a method for determining a Market Heat Rate), and if Buyer and the Trade Organizations have not so agreed on or before the twelfth (12th) Trading Day after which the Market Disruption Event occurred or existed, then the Market Heat Rate will be determined in good faith by taking the average of the price quotations for electric energy and relevant Trading Days that are obtained from no more than two (2) Reference Market-Makers selected by each of Buyer and the Trade Organizations (for a total of four (4) price quotations). Seller hereby agrees and acknowledges that it shall be bound by any agreement as to a Market Heat Rate (or a method for determining a Market Heat Rate) between Buyer and the Trade Organizations, in accordance with the foregoing. *** End of Exhibit S ***

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 7

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

EXHIBIT T QF Efficiency Monitoring Program – Cogeneration Data Reporting Form 2244 Walnut Grove Ave, Rosemead, CA 91770 QF Efficiency Monitoring Program Administrator, (626) 302-9110 [email protected] [PrevYear] I.

Name and Address of Project Name: Street: City: ID No.: ________

II. In Operation: Yes

State:

Zip Code:

Generation Nameplate (KW): __________________ No

III. Can your facility dump your thermal output directly to the environment?

Yes

No

IV. Ownership Ownership

Name

Address

(%)

1 2 3 4 5

Utility Y N Y N Y N Y N Y N

V. [PrevYear] Monthly Operating Data 

Indicate the unit of measure used for your useful thermal output if other than mBTUs: BTUs Therms mmBTUs



If Energy Input is natural gas, use the Lower Heating Value (LHV) as supplied by Gas Supplier. Useful Power Output (kWh)

Energy Input (Therms)

Useful Thermal Output (mBtu)

JAN Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yearly Total

Exhibit T Form

QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

Southern California Edison RAP ID #2810, Sycamore Cogeneration Company

*** End of Exhibit T ***

Exhibit T Form

QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN SYCAMORE COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY

This confirmation letter and the appendices attached hereto and incorporated herein (“Confirmation”) confirms the Transaction between Sycamore Cogeneration Company (“Seller” or “Sycamore”) and Southern California Edison Company (“Buyer” or “SCE”) dated as of October 15, 2012 (“Confirmation Effective Date”) regarding the sale and purchase of the Product, as such term is defined below in Section 1.5, in accordance with and subject to the terms and provisions of this Confirmation, the EEI Master Power Purchase & Sale Agreement, together with the Cover Sheet (the “Transition Cover Sheet”), any amendments and annexes thereto between Seller and SCE dated as of October 15, 2012 (“Transition Master Agreement”), and Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement.” Capitalized terms used but not defined in this Confirmation shall have the meanings ascribed to them in the Transition EEI Agreement or the Tariff. If any term in this Agreement conflicts with the Tariff, the definition set forth in this Agreement shall supersede.

RECITALS

A.

Seller owns and operates Generating Unit # 2 and Generating Unit # 4, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement.

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement.

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition RA Confirmation and the Transition PPA.

ARTICLE 1 TRANSACTION DEFINITIONS 1.1

Seller

Sycamore Cogeneration Company. 1.2

Buyer

SCE. 1.3

Term

The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied; provided, however, that: (i) before the commencement of the Delivery Period, SCE must have obtained, in its sole discretion or waived, CPUC Approval, and (ii) before the commencement of the Delivery Period, FERC Approval as set forth in the Transition PPA must have been obtained.

1

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

1.4

Delivery Period

The “Delivery Period” commences on the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained; provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition PPA and Transition RA Confirmation have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), and ends the date that is immediately prior to the commencement of the ‘Delivery Period’ under and as defined in the RFO Agreement, which shall be no later than June 30, 2014 (the “Delivery Period End Date”); provided, however if ‘CPUC Approval’ (as defined in the RFO Agreement) and/or ‘FERC Approval’ (as defined in the RFO Agreement) of the RFO Agreement are not obtained prior to June 30, 2014, through no fault of Seller, then the Delivery Period End Date shall be June 30, 2015. 1.5

Product

Capacity, Energy, Ancillary Services, and any other product derived from or associated with each Generating Unit including any Green Attributes associated with the Capacity, Energy and Ancillary Services (collectively, the “Product”). During the Delivery Period, Seller shall sell and deliver, and SCE shall purchase and receive, the Product, subject to the terms and conditions of this Confirmation; provided, however, that Seller’s Allowances shall be treated in accordance with Article 20. Seller represents, warrants, and covenants that it will deliver the Product to SCE free and clear of all liens, security interests, claims, and encumbrances. Seller shall not substitute or purchase the Product or any portion of the Product from any other generating resource or from the market for delivery hereunder. 1.6

Energy Delivery Point

The Energy Delivery Point shall be as described and set forth in the single-line diagram of grid interconnection attached hereto as Appendix 1.6. Except as otherwise set forth in this Confirmation, Seller shall be responsible for all charges and penalties associated with the operation of the Generating Units and transmission of Energy up to and including the Energy Delivery Point, and SCE shall be responsible for all charges and penalties associated with receiving and transmitting Energy after and from the Energy Delivery Point. Title, possession, and risk of loss related to Energy shall transfer from Seller to SCE after the Energy Delivery Point. In the event of a failure by Seller to deliver the Product to the Energy Delivery Point, Article Four of the Transition Master Agreement shall not apply. The Energy Delivery Point specified herein is the Product’s “Delivery Point” for this Transaction for purposes of the Transition EEI Agreement. 1.7

Intentionally Deleted

1.8

Generating Units

Each Generating Unit and its applicable description are set forth in Appendix 1.8. 1.9

No Change to Other Agreements

Notwithstanding anything to the contrary in this Confirmation, Seller and SCE each acknowledge and agree that with respect to the Generating Units which are subject to the obligations under the Agreement, the Transition RA Confirmation and the Transition PPA, any other agreement between Seller and SCE, including any interconnection agreement, is separate and apart from the Agreement, the Transition RA Confirmation and the Transition PPA, such that no other agreement shall modify or add to the Parties’ obligations under the Transition EEI Agreement or this Confirmation, and that no Party’s breach under such other agreement shall excuse a Party’s nonperformance under the Agreement, except as otherwise specifically provided for under this Confirmation.

2

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

ARTICLE 2 PURCHASE AND SALE OF PRODUCT 2.1

Exclusivity

During the Delivery Period, SCE shall have the exclusive right to the Product purchased by SCE hereunder, and all benefits derived therefrom, including the exclusive right to use, market, or resell the Product (or any portion thereof) purchased hereunder and the right to all revenues generated from the use, resale, or marketing of such Product, and Seller may not sell, assign, or otherwise transfer, or commit to sell, assign, or otherwise transfer, the Product (or any portion thereof) or any benefits derived therefrom, to any party other than SCE. In addition, SCE shall have the ability to dispatch each Generating Unit to its PMax at the instruction of the CAISO and subject to the Operating Restrictions applicable to such Generating Unit and shall be entitled to all benefits of such dispatch including all revenues associated with such capacity, energy or ancillary services up to and including the Generating Unit’s PMax. 2.2

Ownership

Seller shall maintain ownership of, and exclusive demonstrable rights to each of the Generating Units throughout the Term.

ARTICLE 3 COMPENSATION AND AVAILABILITY 3.1

Compensation (a)

Monthly Capacity Payment: For each Generating Unit, SCE shall make the Monthly Capacity Payment, payable in arrears, to Seller. The Monthly Capacity Payment for each month of the Delivery Period is set forth in Section C of Appendix 3.1(a), and is subject to reduction in accordance with this Confirmation, including Sections 3.2 and 3.3 below. If the Monthly Capacity Payment is reduced in accordance with this Confirmation, SCE shall make the Reduced Monthly Capacity Payment in lieu of the Monthly Capacity Payment.

(b)

Variable O&M Payment: SCE shall pay Seller a monthly Variable O&M Payment, calculated as follows: n

Variable O&M Paymentm = Variable O&M Chargey *

 Qualifying Delivered Energy

i

i

where: Variable O&M Chargey is set forth in Appendix 3.1(b) m = the relevant month within the Delivery Period being calculated y = the Contract Year corresponding to month “m” n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” (c)

Start-Up Charge: SCE shall pay for the Start-Up Fuel, the Start-Up Charge and the Start-Up Aux Charge for each Start-Up unless specified otherwise in this Confirmation.

3

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

In addition to all Energy produced after a Start-Up, all Energy produced prior to the Generating Unit achieving a Start-Up during the respective start-up cycle shall be for SCE’s account.

(d)

(i)

If SCE aborts a start-up before the Generating Unit achieves full Start-Up, then SCE shall [a] pay for any natural gas consumed by the Generating Unit in connection with such aborted start-up, up to the applicable quantity of the Start-Up Fuel, [b] pay the Start-Up Charge and [c] pay the portion of the Start-Up Aux Charge that is proportional to [i] the amount of Start-Up Aux Energy (MWh) required from the beginning of the Start-Up to the time when such Start-Up was aborted as compared to [ii] the applicable Start-Up Time, provided that such payment shall not exceed the applicable Start-Up Aux Charge.

(ii)

If any Generating Unit is unable to generate or deliver Energy to the Energy Delivery Point after a Start-Up, but before the next scheduled shutdown of such Generating Unit for any reason other than a Force Majeure, SCE is not responsible for any charges under this Section 3.1(c) associated with the next Start-Up.

Fuel Payment: SCE shall pay to Seller a “Fuel Payment” equal to the sum of all Gas Commodity Costs, as defined in 3.1(d)(vi) below, for all applicable calendar days during a calendar month during the Delivery Period for the applicable calendar month. For purposes of calculating the Fuel Payment, the following definitions shall be used: (i)

Gas Index: The index price expressed in $/MMBtu for the applicable flow date published by Platts Gas Daily (in the internet publication currently accessed through www.platts.com) in the table entitled “Daily price survey” under the heading “Citygates” for “Kern River, delivered” under the column “Midpoint” plus $0.01/MMBtu. For the purposes of calculating the Fuel Payment, the Gas Index will be applied to Settlement Intervals on a calendar day basis with each day starting at hour ending 01:00 and not on a Gas Day basis. If the Gas Index ceases to be published, the Parties agree to deem the loss of the Gas Index a “Market Disruption Event” as defined in the Transition Master Agreement and follow the provisions outlined in Section 3.4 of the Transition Master Agreement.

(ii)

Gas Trading Day: The calendar day on which natural gas is traded corresponding to the applicable Gas Index. For example, in the absence of Holidays, a Gas Trading Day on a Monday reflects the day-ahead price applicable to gas flow on Tuesday. A Gas Trading Day on a Friday, in the absence of a Holiday, reflects the price for gas flow on Saturday, Sunday, and Monday.

(iii)

Required Natural Gas Quantity: The Required Natural Gas Quantity for each calendar day shall be expressed in MMBtu and equal to the sum of: [a]

[b]

the quantity of natural gas required for each Settlement Interval of the calendar day, calculated by multiplying: (1)

MWh of Qualifying Delivered Energy in such Settlement Interval by

(2)

the lesser of [i] the Heat Rate specified in Appendix 5.3 applicable to the product of the Scheduled Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour, or [ii] the Heat Rate specified in Appendix 5.3 applicable to the product of the Qualifying Delivered Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour; and

any Start-Up Fuel required during the relevant calendar day; provided that in the event the duration of a Start-Up extends past one calendar day, then all of the Start-Up Fuel will be allocated to the calendar day associated with the first nonzero hourly schedule.

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3.2

(iv)

Day Ahead Gas Quantity: The quantity of natural gas (expressed in MMBtu), if any, determined by SCE on each Gas Trading Day for an estimated dispatch on all calendar days associated with such Gas Trading Day. For example, in the absence of a Holiday, the Day-Ahead Gas Quantities for Saturday, Sunday, and Monday shall be calculated by SCE and provided to Seller on the immediately preceding Friday, and the Day-Ahead Gas Quantity for Tuesday shall be calculated by SCE and provided to Seller on the immediately preceding Monday.

(v)

Adjustment Gas Quantity: The Adjustment Gas Quantity for each calendar day shall equal the Required Natural Gas Quantity minus the Day-Ahead Gas Quantity corresponding to the applicable calendar day.

(vi)

Gas Commodity Cost: The Gas Commodity Cost shall equal the sum of the Day Ahead Gas Cost and Adjustment Gas Cost

(vii)

Day-Ahead Gas Cost: The Day-Ahead Gas Cost shall equal the Day-Ahead Gas Quantity multiplied by the applicable Gas Index for such Day-Ahead Gas Quantity.

(viii)

Adjustment Gas Cost: If the Adjustment Gas Quantity for a calendar day is: (a)

positive, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index published for and on the Gas Trading Day associated with the applicable Operating Day plus $0.35/MMBtu; or

(b)

negative, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the lower of the Gas Index (i) used for the Day-Ahead Gas Cost, or (ii) published for the next Gas Trading Day immediately following the applicable Operating Day; unless the Generating Unit(s) had a Forced Outage, that renders the entire unit(s) unavailable, declared for any Settlement Interval. In such cases, the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index used for the Day-Ahead Gas Cost, from the first date of the occurrence of the Forced Outage up to and including the date when the next Generating Unit Start-Up is completed.

Availability (a)

Capacity Payment Reduction. If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), (i) the Available Capacity of a Generating Unit is less than its Contract Capacity in any Settlement Interval in a month during the Delivery Period, or (ii) the Qualifying Delivered Energy from such Generating Unit is less than the Performance Tolerance Band Lower Limit in any Settlement Interval in a month during the Delivery Period, then the Capacity Payment Reduction for the affected Generating Unit for that month will be calculated as follows: (i)

For each Settlement Interval in the month, the “Price-Weighted Capacity Availability” is calculated as follows: Price-Weighted Capacity Availabilityi = (AMCPh(i) * Capacity Availabilityi) / AMCPavg(m) where: i = the Settlement Interval in month “m”

 MCP , if MCP  0 if MCP  0  0,

AMCP = 

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h(i) = the Trading Hour corresponding to Settlement Interval “i” being calculated avg(m) = the simple average over all Settlement Intervals in month “m” For purposes of such calculation, Capacity Availability for any Settlement Interval shall not exceed the applicable Contract Capacity. (ii)

Using the Price-Weighted Capacity Availability calculated above, the “Price-Weighted Monthly Capacity Availability” for month “m” is calculated as follows: n

Price-Weighted Monthly Capacity Availabilitym =

 Price-Weighted Capacity Availabilityi i

where: m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” (iii)

Using the Price-Weighted Monthly Capacity Availability calculated above, the “Capacity Price Adjustment Factor” for month “m” is calculated as follows: Capacity Price Adjustment Factorm = Price-Weighted Monthly Capacity Availabilitym / (Q * n) where: m = the relevant month within the Delivery Period being calculated Q = the Contract Capacity n = the number of Settlement Intervals in month “m”

(iv)

Finally, using the Capacity Price Adjustment Factor calculated above, the “Capacity Payment Reduction” for month “m” is calculated as follows: Capacity Payment Reductionm,CCGT / BOILER = 0.85 * Monthly Capacity Payment * (1 –Capacity Price Adjustment Factor)

(b)

Ancillary Services Capacity Payment Reduction: If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), for each Ancillary Service listed in Section F of Appendix 1.4, the A/S Availability of a Generating Unit is less than the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4 in any Settlement Interval of a month, then the A/S Capacity Payment Reduction for the Generating Unit for that month will be calculated as follows: (i)

The “Monthly Available A/S Capacity” for month “m” is calculated as follows: n

Monthly Available A/S Capacitym =

 A/S Availability k

i,k

i

where: m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m”

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i = the Settlement Interval in month “m” k = the applicable Ancillary Service For purposes of such calculation, for each Ancillary Service, A/S Availability for any Settlement Interval shall not exceed the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4. (ii)

Using the Monthly Available A/S Capacity calculated above, the “A/S Price Adjustment Factor” for month “m” is calculated as follows: A/S Price Adjustment Factorm = Monthly Available A/S Capacitym / ( A/S Maximum Capacityk * n)

 k

where: A/S Maximum Capacity is set forth in Section F of Appendix 1.4 m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” k = the applicable Ancillary Service (iii)

Using the A/S Price Adjustment Factor calculated above, the “A/S Capacity Payment Reduction” for month “m” is calculated as follows: A/S Capacity Payment Reductionm,CCGT/ BOILER = 0.15 * Monthly Capacity Payment * (1 – A/S Price Adjustment Factor)

(c)

3.3

Reduced Monthly Capacity Payment: The “Reduced Monthly Capacity Payment” shall be equal to (i) the Monthly Capacity Payment less (ii) the sum of [a] the Capacity Payment Reduction and [b] the A/S Capacity Payment Reduction.

Other Events Affecting Availability (a)

If Seller fails to take any action necessary to make the Product (or any portion of the Product) deliverable or otherwise available to SCE at the Energy Delivery Point, including maintenance, repair, or replacement of equipment in Seller’s possession or control that must be used for SCE to take delivery of the Product after, or transmit the Product from, the Energy Delivery Point, or such equipment fails for any reason including by reason of Force Majeure or any Outage, then, to the extent SCE is unable to take delivery of the Product after, or to transmit the Product from, the Energy Delivery Point by reason of such failures by Seller, the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(b)

If Seller fails to take any action within its control that is necessary to deliver the Natural Gas Requirements to the Generating Unit(s), including maintenance, repair or replacement of equipment in Seller’s possession or control that must be used to deliver the Natural Gas Requirements to the Generating Unit(s), or such equipment in Seller’s possession or control fails for any reason, including by reason of Force Majeure or any Outage, then, to the extent the Natural Gas Requirements are unable to be delivered to the Generating Unit(s), the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with

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Section 3.2 above. (c)

If the IFA, the PGA, or the MSA are not in effect at any time during the Delivery Period, the Generating Units shall be deemed to be unavailable for the Settlement Intervals during which such agreement or agreements are ineffective, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(d)

If Seller starts-up or operates any Generating Unit other than (i) pursuant to a Dispatch Notice or (ii) pursuant to a Non-SCE Dispatch, the Generating Unit shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

ARTICLE 4 FUEL RESPONSIBILITIES 4.1

SCE’s Obligation

SCE shall provide the Day Ahead Gas Quantity to Seller by 6:00 AM (PPT) on the Gas Trading Day applicable to each calendar day of the Delivery Period and be responsible for costs associated with providing the Required Natural Gas Quantity to the Generating Units solely through the Fuel Payment as set forth in Section 3.1(d). SCE shall not be obligated to reimburse Seller for any separate charges assessed to Seller for gas transportation surcharges, fuel retention charges, imbalances, penalties, storage costs, or fuel-related taxes. 4.2

Seller’s Obligation

Seller shall be responsible for managing, nominating, scheduling, balancing, and transporting all of the Natural Gas Requirements needed to operate each Generating Unit. Seller shall also be responsible for all costs of natural gas associated with a Seller’s Initiated Test as set forth in Article 10.

ARTICLE 5 COMBINED HEAT AND POWER (“CHP”) PROGRAM PROVISIONS 5.1

CHP Program Procurement and Seller Eligibility

Seller and SCE acknowledge and agree that SCE is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by SCE pursuant to this Confirmation is and shall be deemed to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to SCE that as of the Confirmation Effective Date, Generating Unit # 2 and Generating Unit # 4, together with the generating units that are subject to the obligations in the Transition PPA, constitute a Qualifying Facility. 5.2

CPUC Approval; FERC Approval (a)

Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby,

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including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report.

5.3

(c)

Failure to obtain CPUC Approval in accordance with this Section 5.2(a) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of SCE to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval.

(d)

Failure to obtain FERC Approval in accordance with this Section 5.2(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

Provision of Information

Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement.

ARTICLE 6 SCHEDULING COORDINATOR SERVICES 6.1

SCE as Scheduling Coordinator

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall take all actions and execute and deliver to SCE and the CAISO all documents necessary to authorize or designate SCE as Scheduling Coordinator (“SC”) for each of Generating Unit # 2 and Generating Unit # 4 with the CAISO effective as of the beginning of the Delivery Period. Seller shall not be entitled to any payment under this Confirmation until SCE is fully authorized as the SC for each such Generating Unit. During the Delivery Period, and after SCE is designated as SC for a Generating Unit, Seller shall not authorize or designate any other party to act as SC, nor shall Seller perform for its own benefit the duties of SC, and Seller shall not revoke SCE’s authorization to act as SC unless agreed to in writing by SCE. SCE shall submit bids and schedules to the CAISO in accordance with the Tariff and, subject to Article 9 below, the Operating Restrictions. Seller shall reasonably cooperate with SCE in performing any actions necessary prior to the start of the Delivery Period to allow each of Generating Unit # 2 and Generating Unit # 4 to be (i) dispatched (or otherwise scheduled to operate) for the first day of the Delivery Period and (ii) reported to or scheduled with the CAISO pursuant to the Tariff, either through SLIC or as otherwise required by the CAISO, as being in an outage at the commencement of the Delivery Period. All CAISO costs and revenues (including credits

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and other payments) associated with a dispatch of Generating Unit # 2 or Generating Unit # 4 on the first day of the Delivery Period that are received by Seller or their SC on the day prior to the Delivery Period shall be for SCE’s account. 6.2

Notices

Subject to Seller complying with its obligations under this Confirmation, SCE, as SC, shall submit all notices and updates required under the Tariff regarding each Generating Unit’s status to the CAISO. Seller will comply with Article 9 of this Confirmation in providing such notices and updates. 6.3

CAISO Settlements

As SC, SCE shall be responsible for all settlement functions with the CAISO related to the Generating Units. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to the Generating Units, including any invoices or settlement data, in the format reasonably requested by SCE. 6.4

Terminating SCE’s Designation as SC

At least thirty (30) days prior to the expiration of the Delivery Period, the Parties will take all actions necessary to terminate the designation of SCE as SC as of 11:59 p.m. on the final date of the Delivery Period (“SC Replacement Date”). Such actions include the following: (a) Seller shall (i) submit to the CAISO a designation of a new SC to replace SCE effective as of the SC Replacement Date and (ii) cause its newly designated SC to submit a letter to the CAISO accepting the designation; and (b) SCE shall submit a letter to the CAISO resigning as SC effective as of the SC Replacement Date. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement SC. 6.5

Duties Related to Resource Adequacy Resources

If a Generating Unit is designated as a Resource Adequacy Resource, the following will apply: (a)

Seller shall take all actions necessary in order to allow SCE to reasonably perform its duties as an SC for a Resource Adequacy Resource, including, but not limited to, providing all information needed for SCE to include the Generating Units on SCE’s Supply Plan; and

(b)

SCE shall use the Resource Adequacy Availability Management (“RAAM”) software to allow Seller to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”), provided, (i) SCE is not required to use or change its utilization of SCE owned or controlled assets or market positions, to allow Seller to utilize the Substitution Rules, (ii) Seller, at its own expense, provides substitute capacity that complies with the Substitution Rules, (iii) Seller provides, as soon as practicable, but no later than 5:00 a.m. PPT the day bids are due in the IFM for the day Seller seeks to substitute capacity for, all information to SCE needed to substitute capacity pursuant to the Substitution Rules, including, but not limited to, the substitution start and end dates, the Resource ID for the substitute unit, a short description of the outage, the outage ID from SLIC application, and the amount of capacity to be substituted, (iv) SCE’s duties to take action under this subsection (b) are solely limited to inserting one (1) substitution request through RAAM per day; and (v) Seller causes, and is responsible for, the SC of the generating unit Seller seeks to substitute with to cooperate with SCE in making a substitute request and SCE is not responsible or liable for any costs, damages, penalties, charges, or liabilities (“Substitution Costs”) associated with such SC’s failure to cooperate or take the proper action; provided, further, if the CAISO develops a tool, application, or other means, for Seller to submit its own substitution request, then SCE shall not be required to take any action under this Section 6.5(b) to allow Seller to utilize the Substitution Rules. In no event shall SCE be responsible or liable for any Substitution Costs associated with Seller’s inability to utilize the Substitution Rules or rejection by the CAISO of any substitute capacity for any reason, including, but not limited to, any RAAM software limitations or failures, unless SCE is required to take action and such Substitution Costs or rejection result solely from SCE’s actions.

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Seller shall provide the information set forth in Section 6.5(b)(iii) through the Outage Management System. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide such information through (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission of such information as soon as practicable.

ARTICLE 7 RMR DESIGNATION 7.1

RMR Contract

Upon the request or designation by the CAISO that any of the Generating Units be an RMR Unit, whether such request or designation is made directly by the CAISO or at the CAISO’s direction through the Scheduling Coordinator, Seller shall enter into an RMR Contract with CAISO under terms and conditions reasonably acceptable to SCE and Seller. Seller shall not otherwise pursue or enter into an RMR Contract without SCE’s consent. If any Generating Unit is or becomes an RMR Unit during the Delivery Period, then for any dispatch by CAISO under the RMR Contract, the Operating Restrictions under this Confirmation will be subject to and superseded by any operating restrictions set forth in the RMR Contract or in the CAISO Master File for those Generating Units. Nothing in this Confirmation shall be construed to be a limitation on SCE’s right as a Transmission Owner under the Tariff to file with, or petition, to the FERC any objection or comments relating to any such RMR Contract or any actions SCE or CAISO intend to take with respect to any such RMR Contract. Seller represents, warrants, and covenants to SCE that if an RMR Contract for any Generating Unit for a period in which it is subject to the obligations in this Confirmation goes into effect at any time during the Term, no assignment of such RMR Contract to SCE will be required in connection with this Transaction. The Parties agree that neither this Confirmation nor this Transaction shall operate as an assignment of any such RMR Contract from Seller to SCE, and that in no event shall SCE be required to assume the obligations of Seller under any such RMR Contract. 7.2

RMR Settlements

If a Generating Unit is designated as a CAISO RMR Unit, then no later than thirty (30) days after such designation by CAISO, Seller shall (i) authorize SCE to act as Seller’s representative (“RMR Settlement Coordinator”) to perform all RMR settlement functions for the RMR Units, (ii) authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder, and (iii) irrevocably assign to SCE all rights to receive any and all payments under the RMR Contract for the Delivery Period. Seller shall take all actions and execute and deliver to SCE all documents or contracts necessary, including any confidentiality agreements or other documents required under the RMR Contract, to authorize or designate SCE with the CAISO as its RMR Settlement Coordinator, and authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder. During the Delivery Period, Seller shall not authorize or designate any other party to act as RMR Settlement Coordinator, nor shall Seller perform for its own benefit the duties of RMR Settlement Coordinator, and Seller shall not revoke SCE’s authorization to act as RMR Settlement Coordinator unless agreed to by SCE. Upon SCE’s designation as the RMR Settlement Coordinator, SCE will be responsible for all RMR settlement functions in accordance with the Tariff and the RMR Contract, including rendering monthly RMR invoices to CAISO, settling any RMR charges incurred or RMR revenues earned, and resolving any RMR-related issues directly with CAISO. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to each of Generating Unit # 2 and Generating Unit # 4 (whether or not such Generating Units are subject to the obligations of this Confirmation at the time such correspondence or communication with the CAISO is

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received by Seller), including any invoices or settlement data, in the format reasonably requested by SCE. Upon receipt of any invoice from the CAISO for an RMR Unit (“RMR Invoice”), Seller shall promptly deliver such RMR Invoice to SCE. If the RMR Invoice amount is a charge from CAISO to Seller, Seller shall submit an invoice to SCE setting forth the amounts owed under the RMR Invoice, and SCE shall pay such amount to Seller for remission to CAISO within ten (10) Business Days after SCE’s receipt of such invoice. If the RMR Invoice amount is a payment from CAISO to Seller, Seller shall remit the amount of such payment to SCE within ten (10) Business Days after Seller’s receipt of such payment. To secure Seller’s obligations to remit to SCE any payments received under an RMR Contract or pursuant to an RMR Invoice, Seller hereby grants to SCE a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all revenues and accounts receivable of Seller with respect to the RMR Contract, and any and all proceeds resulting therefrom (collectively, “RMR Revenues”), whether now or hereafter held by, on behalf of, or for the benefit of, SCE, and Seller agrees to take such action as SCE reasonably requires in order to perfect SCE’s first-priority security interest in, and lien on (and right of setoff against) such RMR Revenues. SCE shall be the Secured Party with respect to the RMR Revenues and shall have all the rights and remedies of the Secured Party under the Transition EEI Agreement with respect to those RMR Revenues. 7.3

Disputes of RMR Invoices

The Parties agree that all RMR Invoices are subject to the Tariff and may be adjusted by the CAISO, or disputed by SCE, as RMR Settlement Coordinator, in accordance with the Tariff. The Parties agree that all RMR Invoices are subject to dispute between the Parties in accordance with Article Six of the Transition Master Agreement; provided, that the time limitation for adjustments or disputes of invoices set forth in Section 6.3 of the Transition Master Agreement shall not apply to RMR Invoices. Notwithstanding anything to the contrary contained in Articles Six or Ten of the Transition Master Agreement, the Parties agree that the obligations under this Article 7 with respect to the payment of RMR Invoices, or the adjustment of such RMR Invoices, shall survive the expiration or termination of this Confirmation for a period of one year beyond the time period which CAISO may adjust, modify or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the Tariff. 7.4

Terminating SCE’s Designation as RMR Settlement Coordinator

SCE’s designation as RMR Settlement Coordinator will remain in effect until the last applicable RMR Invoice and the data associated therewith is received by SCE and SCE completes all RMR settlement functions associated with such final RMR Invoice. In no event shall SCE be the RMR Settlement Coordinator for any operating day that is not within the Delivery Period. A new SC or RMR Settlement Coordinator shall not affect SCE’s ability to receive RMR settlement payment for any Generating Unit for any operating day during the Delivery Period when an RMR contract is in effect between Seller and the CAISO for such Generating Unit.

ARTICLE 8 CAISO AND DELIVERY DEVIATION CHARGES 8.1

CAISO Costs and Revenues

Except as otherwise set forth in this Confirmation, SCE shall be responsible for CAISO costs and receive all CAISO revenues (including credits and other payments) incurred in connection with providing SC services, including costs and revenues associated with SCE and CAISO dispatches of any Generating Unit. The procedures and calculation methodologies set forth in this Article 8 regarding CAISO costs and revenues are in respect to each Generating Unit. 8.2

CAISO Sanctions

If, during the Term, the CAISO implements or has implemented any sanction or penalty related to scheduling, outage reporting, or generator operation, and any such sanctions or penalties are imposed upon the Generating

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Unit(s) or to SCE as SC due solely to the actions or inactions of Seller, the cost of the sanctions or penalties shall be the Seller’s responsibility. 8.3

Scheduling and Delivery Deviation Charge

Seller shall pay SCE an SDD Charge if during any Settlement Interval the Qualifying Delivered Energy is less than the Performance Tolerance Band Lower Limit for such Settlement Interval. The SDD Charge is calculated as follows: If A < B, then SDD Charge = 0.5 * (B – A) * C where: A = Qualifying Delivered Energy for the Settlement Interval; B = Performance Tolerance Band Lower Limit; and C = SDD Price. Upon CAISO’s implementation of UDP, or any subsequent changes regarding the calculation of UDP, the Parties agree to negotiate in good faith to amend the SDD Charge calculation as necessary to maintain the economic balance of benefits and burdens contemplated under this Section 8.3. 8.4

SDD Administrative Charge

Seller shall pay SCE an SDD Administrative Charge if during any Settlement Interval Delivered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, for such Settlement Interval. The SDD Administrative Charge is calculated as follows: SDD Administrative Charge = Absolute Value (E – D) * F where: D = Delivered Energy for the Settlement Interval; E = Scheduled Energy for the Settlement Interval; and F = SDD Admin Price. 8.5

Allocation of Standard Capacity Product Payments and Charges

Seller agrees that, if the Generating Unit is a Resource Adequacy Resource, then it is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account. 8.6

Allocation of Charges Related to Generator Replace Tariff Provisions

If (a) a Generating Unit is designated as a Resource Adequacy Resource and (b) FERC approves or modifies the Tariff whereby, during periods that the Generating Unit is on a Planned Outage, the SC for a Resource Adequacy Resource is required to (i) replace the Generating Unit with a resource that is not a Resource Adequacy Resource or (ii) face the imposition of a charge, cost, sanction and/or penalty for failing to replace that Generating Unit, then

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Seller is responsible for (x) replacing the Generating Unit with a resource that is not a Resource Adequacy Resource, and (y) any and all charges, costs, sanctions and/or penalties for failing to replace all or a portion of the Generating Unit. Seller agrees that SCE is not required to take any action, or use or change its utilization of its owned or controlled assets or market positions, to allow Seller to replace the Generating Unit with a resource that is not a Resource Adequacy Resource; provided that SCE in its capacity as SC shall remain liable for compliance by it with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 9 AVAILABILITY NOTICES, BIDS, AWARDS AND DISPATCH 9.1

Notice of Availability

With respect to each Operating Day, no later than two (2) Business Days before each Trading Day, Seller shall provide to SCE using an SCE-provided web-based system (“Outage Management System”) an hourly schedule of the Available Capacity (for both Energy and Ancillary Services) that each Generating Unit is expected to have available for each hour of the applicable Operating Day (the “Availability Notice”). Seller must update SCE immediately using the Outage Management System if the Available Capacity of any Generating Unit changes or is likely to change after the Availability Notice has been submitted to SCE. Seller must follow up each such update through the Outage Management System with a telephonic update to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e). Seller shall accommodate SCE’s reasonable requests for changes in the time or form of delivery of the Availability Notices. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide Availability Notices using the form attached in Appendix 9.1 by (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission notice of such availability as soon as practicable. 9.2

Dispatch Notices and Operating Restrictions (a)

Dispatch Notices. SCE will have the right to dispatch each Generating Unit, seven (7) days per week and twenty-four (24) hours per day (including Holidays) and (i) at any level between PMin and Contract Capacity, inclusive, and (ii) at any level between Contract Capacity and PMax if instructed by the CAISO by providing Dispatch Notices to Seller electronically, subject to the terms and conditions set forth in this Confirmation. Subject to the Operating Restrictions, each Dispatch Notice will be effective unless and until SCE modifies such Dispatch Notice by providing Seller with an updated Dispatch Notice. If an electronic submittal is not possible for reasons beyond SCE’s control, SCE may provide Dispatch Notices by (in order of preference) electronic mail, facsimile transmission, or telephonically to the Seller personnel designated to receive such communications as listed in the Appendix 9.2(e). Day-Ahead Dispatch Notices, in the absence of an electronic submittal, shall be provided in a form substantially similar to Appendix 9.2(a). In addition to any other requirements set forth in this Confirmation, all Dispatch Notices will be made in accordance with the Tariff.

(b)

Start-Up Notices. If a Dispatch Notice includes a Start-Up, Seller shall notify SCE electronically when the respective Generating Unit has initiated a turbine start and again when that Generating Unit is synchronized and at Minimum Load ready to be dispatched to the applicable dispatch instruction. Seller shall provide an electronic or facsimile copy of a completed Start-Up Notice, in the form attached to this Confirmation in Appendix 9.2(b), to SCE within twenty-four (24) hours of the Start-Up. When a Dispatch Notice requires a Start-Up or shutdown, Seller will be responsible for coordinating all required switchyard switching with the respective grid control center, if applicable.

(c)

Operating Restrictions. The Operating Restrictions associated with the Product are specified in Appendix 1.4. In providing a Dispatch Notice, SCE shall use reasonable efforts to comply with the applicable Operating Restrictions. If SCE submits a Dispatch Notice that does not conform with the

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Operating Restrictions, then Seller shall immediately notify SCE of the non-conformity and SCE will modify its Dispatch Notice to conform to the applicable Operating Restrictions. Until such time as SCE submits a modified Dispatch Notice, Seller shall operate the applicable Generating Unit and deliver the Product in accordance with the Operating Restrictions.

9.3

(d)

Daily Operating Report. Seller shall provide SCE the Daily Operating Report, in the form attached in Appendix 9.2(d), the day immediately after each Operating Day, for all Generating Units.

(e)

Communication Protocols. The Parties shall agree to the communication protocols outlined in Appendix 9.2(e) to facilitate exchange of information between the Parties.

CAISO Dispatch

Any award or dispatch of a Generating Unit by the CAISO for any reason (whether pursuant to an RMR Contract, must offer obligations, Energy dispatches or otherwise), shall be deemed to be a dispatch by SCE for purposes of this Confirmation. The Energy dispatched shall be for SCE’s benefit hereunder, and SCE shall pay the costs of such CAISO awards and dispatches in accordance with the terms of this Confirmation as if such dispatches were directed by SCE. SCE shall be entitled to receive and retain for its own account any and all CAISO revenues for such awards and dispatches, including any availability payments under an RMR Contract for any Generating Unit. In no event shall a dispatch by the CAISO be considered a Non-SCE Dispatch pursuant to this Confirmation. CAISO dispatches following any Seller Initiated Test pursuant to Section 10.1 shall not obligate SCE for any associated costs incurred in starting any Generating Unit for, or operation during, such testing period. 9.4

Non-SCE Dispatch

During the Delivery Period, Seller shall not start-up or operate any Generating Unit other than (a) pursuant to a Dispatch Notice or (b) pursuant to a Non-SCE Dispatch. Seller shall, to the extent possible, notify SCE no later than 5:00 a.m. PPT at least two (2) Business Days in advance of the Trading Day of any start-up or operation pursuant to a Non-SCE Dispatch, and shall, except as otherwise required by Applicable Law, delay such start-up or operation if requested by SCE. Seller shall indemnify, defend, and hold SCE harmless against the costs or losses of SCE resulting from a Non-SCE Dispatch, including all (i) charges, sanctions, and penalties imposed by CAISO, and (ii) Seller’s Gas Costs incurred pursuant to any such start-up or operation. Imbalance Energy revenues net of any charges, sanctions, and penalties imposed by CAISO for a Non-SCE Dispatch shall be for Seller’s account.

ARTICLE 10 TESTING 10.1

Testing

Seller may, at times and for durations reasonably agreed to by SCE, conduct necessary testing of the Generating Units. (a) Seller is permitted to conduct such testing during the hours in which Seller receives a Dispatch Notice (“SCE Dispatched Test”). Seller shall not be obligated to pay for the Fuel Payment relating to such SCE Dispatched Test, and SCE shall be responsible for all CAISO costs incurred and receive all revenues during such SCE Dispatched Test in accordance to Section 8.1 of this Confirmation. (b) Subject to Section 10.1(a), if Seller wishes to schedule and conduct a test (“Seller Initiated Test”), SCE shall not be obligated to pay the Fuel Payment to Seller, and Seller shall pay for all costs (including, but not limited to, start-up, fuel and/or transportation costs) relating to and arising out of such Seller Initiated Test in accordance with Section 9.4 of this Confirmation, and SCE shall pay to Seller, in the month following SCE’s receipt of such CAISO revenues, such revenues net of any resource specific charges, penalties, or sanctions associated with the Energy generated and delivered during such Seller Initiated Test. To the extent such Seller Initiated Test prevents SCE from dispatching any Generating Unit as it

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

would have absent such test, then, in accordance with the Section 3.2 of this Confirmation, the Generating Unit will be deemed unavailable. Seller must notify SCE of any Seller Initiated Test no later than 5:00 a.m. PPT at least three (3) Business Days in advance of the Trading Day of any start-up, operation or operational limitation(s) pursuant to the requested test. If Seller Initiated Test is agreed upon by SCE, SCE shall have the option to submit a SelfSchedule in the IFM for the agreed upon testing day for a duration the greater of (i) the number of hours required to complete the test, or (ii) the Minimum Run Time as referenced in Section B of Appendix 1.4. Notwithstanding anything to the contrary in this Confirmation, such Self-Schedule is not considered a Dispatch Notice. 10.2

SCE Annual Test

At least once per calendar year at SCE’s request, SCE has the right to require Seller to demonstrate, pursuant to the protocols set forth in Appendix 10.2 (the “SCE Annual Test”), each Generating Unit’s ability to provide the Product in accordance with the terms of this Confirmation. In addition, as part of the SCE Annual Test, SCE may inspect the Generating Facility to confirm the configurations of the Generating Unit(s) provided for in Appendix 1.4. The SCE Annual Test shall be at a time mutually agreed to by the Parties. If, during an SCE Annual Test, a Generating Unit fails to demonstrate its ability to provide the Product or any portion thereof (a “Failed Test”), Seller shall, at Seller’s cost and expense, promptly make all necessary repairs to such Generating Unit, and any portion thereof, and/or take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation. The results of any Failed Test will be used to determine the Available Capacity for the applicable Generating Unit, and accordingly, Reduced Monthly Capacity Payments shall apply for such Generating Unit until Seller demonstrates, in accordance with Appendix 10.2, a successful test. Seller agrees that any subsequent test that is required to demonstrate compliance for a Failed Test shall be a Seller Initiated Test.

ARTICLE 11 OUTAGES 11.1

Planned Outages

No later than 60 days prior to the Delivery Period, and no later than January 1, April 1, July 1, and October 1 of each calendar year thereafter throughout the Term, Seller shall submit to SCE the portion of the Seller’s schedule of proposed Planned Outages (“Outage Schedule”) for the following twenty-four (24) month period that overlaps the Delivery Period via the Outage Management System. If the Outage Management System is not available, Seller shall submit the Outage Schedule in substantially the form set forth in Appendix 11.1. Within twenty (20) Business Days after its receipt of an Outage Schedule, SCE shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Accepted Electrical Practices, accommodate SCE’s requests regarding the timing of any Planned Outage. Seller shall cooperate with SCE to arrange and coordinate all Outage Schedules with the CAISO in compliance with all CAISO Outage scheduling and reporting requirements. Seller will communicate to SCE all changes to a Planned Outage including estimated time of return of each Generating Unit as soon as practicable after the condition causing the change becomes known to Seller. 11.2

Restrictions to Planned Outages (a)

No Planned Outages shall be scheduled or planned from each May 1 through September 30 during the Delivery Period for any Generating Unit subject to this Confirmation, without prior written consent from SCE.

(b)

In the event that the Seller has a Planned Outage for any Generating Unit subject to this Confirmation that becomes coincident with a CAISO-declared system emergency, Seller shall make

16

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

all reasonable efforts to reschedule such Planned Outage. 11.3

Notice of Forced Outages

Seller shall communicate Forced Outages by telephoning SCE’s Generation Operations Center within ten (10) minutes of the commencement of the Forced Outage, at the telephone numbers listed in Appendix 9.2(e). Seller shall utilize SCE’s Outage Management System to enter Outage information as required by the Tariff within twenty (20) minutes of the Forced Outage. If the CAISO imposes a sanction or penalty upon SCE as SC due to Seller’s failure to timely provide SCE with a report of a Forced Outage or Planned Outage for any Generating Unit subject to this Confirmation, Seller shall be responsible for such sanction or penalty. 11.4

Reports of Forced Outages or Planned Outages

Seller shall promptly prepare and provide to SCE, using the Outage Management System or forms, all reports of Forced Outages or Planned Outages for any Generating Unit subject to this Confirmation that SCE may reasonably require for the purpose of enabling SCE to comply with CAISO requirements or any Applicable Laws. Seller shall provide to SCE notice of a Planned Outage no later than seventy-two (72) hours prior to the beginning of any Planned Outage. Seller shall also report all Forced Outages and Planned Outages in the Daily Operating Report. 11.5

Inspection

In the event of a Forced Outage, SCE shall have the right to inspect any Generating Unit and all records relating thereto on any Business Day and at a reasonable time, and Seller shall reasonably cooperate with SCE during any such inspection.

ARTICLE 12 METERING, COMMUNICATIONS, AND TELEMETRY 12.1

SCE Access

All communication, metering, telemetry, and associated generation operation equipment will be centralized into each Generating Unit’s Distributed Control System (“DCS”). Seller shall configure each Generating Unit’s DCS so that SCE may access it via the Generation Management System (“GMS”) from SCE’s Generation Operations Center (“GOC”). Seller shall ensure that the access link will provide a monitoring and control interface to enable automatic dispatch of each Generating Unit. Seller shall link the systems via an approved SCE communication network, utilizing existing industry standard network protocol, as approved by SCE. The connection will be bidirectional in nature and used by the Parties to exchange all data points to and from the GOC. SCE and Seller shall each have shared access to information concerning gas data (including data regarding nominations, confirmations, allocations, imbalances, and usage) through electronic bulletin boards or remote meter reading devices with respect to all Natural Gas Requirements for each Generating Unit. Seller shall be responsible for the costs of installing, configuring, maintaining and operating the DCS for each Generating Unit. 12.2

Control Logic

Seller will ensure that each Generating Unit’s DCS control logic will be configured to control the Generating Unit in multiple plant configurations as applicable. Each Generating Unit’s control logic will incorporate control signals from multiple locations to perform Energy dispatch, Ancillary Services, and supplemental energy functions. Control logic will perform all coordinated megawatt control and Automatic Generation Control (“AGC”) independently for each Generating Unit.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

12.3

Delivery of Data

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall provide SCE with all facility and metering information necessary to communicate with SCE, including the information set forth in Appendix 12.3. 12.4

Satellite Communication System

Seller is responsible for installing, testing, commissioning, and maintaining the Satellite Communications System (“SCS”) for each Generating Unit in accordance with instructions provided by SCE and the SCS vendor. Seller shall grant SCE reasonable access to the Generating Units during regular business hours for routine calibration and maintenance of the SCS at any time prior to the expiration of the Delivery Period. SCE may, at any time, halt the installation, testing, commissioning, or maintenance of the SCS. SCE shall be responsible for the costs associated with installation, testing, commissioning, and maintenance of the SCS, and will provide the SCS to Seller for installation.

ARTICLE 13 OPERATION, MAINTENANCE, AND REPAIR 13.1

Seller’s Operation Obligations During the Delivery Period:

13.2

(a)

Seller shall operate each Generating Unit in accordance with Accepted Electrical Practices, Applicable Laws, Permit Requirements, applicable California utility industry standards, including the standards established by the California Electricity Generation Facilities Standards Committee pursuant to Public Utilities Code Section 761.3 and enforced by the CPUC, CPUC General Order 167, and CAISO mandated standards, as set forth in the Tariff (collectively, “Industry Standards”);

(b)

Seller shall maintain a daily operations log for each Generating Unit which shall include information on power production, fuel consumption and efficiency (if applicable), availability, maintenance performed, Outages, changes in operating status, inspections and any other significant events related to the operation of each Generating Unit. In addition, Seller shall maintain all records applicable to each Generating Unit, including the electrical characteristics of the generators and settings or adjustments of the generator control equipment and protective devices. Information maintained pursuant to this Section 13.1 shall be provided to SCE, within five (5) Business Days of SCE's request; and

(c)

Seller shall maintain and make available to SCE and the CPUC, or any division thereof, records, including the plant operations logbooks demonstrating that the Generating Units are operated and maintained in accordance with Industry Standards. Seller shall comply with all reporting requirements and permit on-site audits, investigations, tests, and inspections permitted or required under Industry Standards.

Seller’s Maintenance and Repair Obligations During the Delivery Period: (a)

Seller shall inspect, maintain, and repair each Generating Unit, and any portion thereof, in accordance with applicable Industry Standards. Seller shall maintain and deliver to SCE within five (5) Business Days upon request, maintenance and repair records and plant equipment test data of each Generating Unit; provided, however, if Seller must obtain such records and data from a thirdparty, Seller shall promptly request such records and data from the applicable third-party and shall provide the requested records and data to SCE within five (5) Business Days of receipt.

(b)

In the event that:

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

(i)

an SCE Annual Test demonstrates that the Available Capacity of a Generating Unit is less than or equal to seventy-five percent (75%) of Contract Capacity, or

(ii)

an equipment failure with respect to a Generating Unit results in the Available Capacity of such unit being less than or equal to seventy-five percent (75%) of Contract Capacity on average for a period of time exceeding seven (7) days,

Seller shall repair such Generating Unit in accordance with Accepted Electrical Practices and the procedure set forth in this Article 13. Within fourteen (14) days of any such failure, Seller shall complete a Successful Repair or present to SCE a written report providing a description of the reason for the failure and a plan and schedule for completing a Successful Repair within the time specified in the repair plan (“Repair Plan”). If SCE and Seller disagree about the Repair Plan, SCE may, at its expense, hire an independent third party engineering firm reasonably acceptable to Seller (“IE”), to assess the situation and make recommendations for completing a Successful Repair. Upon SCE providing two (2) Business Days notice, Seller shall grant the IE and SCE personnel access to the Generating Facility and all relevant operational log books, maintenance records and reports. Seller shall use best efforts to follow the recommendations of the IE’s engineering report for achieving a Successful Repair. Until a Successful Repair is demonstrated, the Generating Unit(s) will be deemed unavailable for purposes of Section 3.2 of this Confirmation; provided, upon Seller’s demonstration of a Successful Repair, the Generating Unit(s) will be deemed available retroactive to the hour that such Successful Repair was initiated;

13.3

(c)

Subject to Section 13.2(b), Seller shall promptly make all necessary repairs to each Generating Unit, and any portion thereof, and take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation; and

(d)

Seller shall not allow the Available Capacity of any Generating Unit to fall below seventy-five percent (75%) of Contract Capacity on average for a period of: (i)

six (6) months (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) due to Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such six (6) month period (or longer cure period identified in the IE’s written report); or

(ii)

sixty (60) days (whether or not consecutive) within a rolling twelve (12) month period (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) for any reason or circumstance, including Forced Outage, but excluding Planned Outage and Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such sixty (60) day period (or longer cure period identified in the IE’s written report).

Operational Representations, Warranties, and Covenants by Seller

Seller represents, warrants, and covenants with respect to Sections 13.3(a) through (d) and Seller covenants with respect to Section 13.3(e) to SCE that: (a)

Prior to the start of the Delivery Period, Seller has executed a PGA and MSA; Seller has delivered to SCE a true and complete copy of such PGA and MSA; and such PGA and MSA, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the duration of the Delivery Period; provided that Seller shall be allowed to agree to any

19

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

amendment or modification to the PGA and/or MSA if FERC approves a new form of such agreements for the CAISO, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10) Business Days of such amendment or modification. (b)

Prior to the start of the Delivery Period, Seller has executed all necessary grid connection, maintenance, or transmission facility services agreements; Seller has delivered to SCE a true and complete copy of such agreements; and such agreements, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the Term; provided that if FERC authorizes the Transmission Owner to amend or modify such agreements with Seller, Seller is authorized to accept any such FERC-approved modified or amendment agreement, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10) Business Days of such amendment or modification.

(c)

Prior to the start of the Delivery Period, Seller has good and defensible title, or valid and effective leasehold rights in the case of leased property, to each Generating Unit subject to this Confirmation , free and clear of all liens, charges, claims, pledges, security interests, equities, and encumbrances of any nature whatsoever other than (i) the lien of current taxes not delinquent; (ii) liens, charges, claims, pledges, security interests, equities, and encumbrances that in the aggregate are not substantial in amount and do not detract from or interfere with the ability of Seller to deliver the Product; or (iii) liens listed in Appendix 13.3(c) delivered by Seller to SCE prior to the Confirmation Effective Date (the “Disclosure Schedule”);

(d)

On the Confirmation Effective Date, the “Historical Outage Report” sets forth true and accurate historical data of (a) the dates during which each Generating Unit (including the Generating Units that will become subject to the obligations of this Confirmation during the Delivery Period) was available to generate Energy during the period from 2009 to the present regardless of whether or not such Generating Unit did in fact generate Energy, and each Generating Unit's capacity to generate Energy for each of those dates during which the Generating Unit was available, and (b) for those dates when each Generating Unit was not available to generate Energy, the reasons for such unavailability; and

(e)

In the event SCE is not the SC, no later than two weeks prior to the first day of the Delivery Period, Seller shall take all actions necessary with the CAISO and SCE to ensure that by the day immediately prior to the first day of the Delivery Period, the CAISO Master File and, if applicable, the RMR Contract reflect the values that SCE deems appropriate based on the Operating Restrictions under this Confirmation. If, at any time prior to the termination of this Confirmation, any action or inaction of Seller, or a condition of any Generating Unit that could result in a revision to the CAISO Master File or to the operating restrictions set forth in an RMR Contract, then Seller shall promptly give notice to SCE and shall use all reasonable efforts to maintain the Operating Restrictions exactly as they existed on the Confirmation Effective Date.

ARTICLE 14 ELECTRIC SYSTEM RELIABILITY STANDARDS During the Delivery Period, Seller shall be (i) responsible for complying with any NERC Reliability Standards applicable to the Generating Units, including registration with NERC as the Generator Operator for the Generating Units or other applicable category under the NERC Reliability Standards and implementation of all applicable processes and procedures required by NERC, WECC or CAISO for compliance with the NERC Reliability Standards; and (ii) liable for all penalties assessed by NERC (through WECC or otherwise) for violations of the NERC Reliability Standards by the Generating Facility or Seller, as Generator Operator or other applicable category. However, if Seller learns that NERC (through WECC or otherwise) is considering or intends to assess Seller with a penalty that Seller believes is attributable to SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the potential assessment, Seller shall provide SCE with sufficient notice to allow SCE to take

20

2012 CHP Energy Only UC Toll (Kern Pipeline··financially seUled gas)

part in administrative processes, discussions or settlement negotiations with NERC, WECC or other entity arising from or related to the alleged violation or possible penalty. If the penalty is nonetheless assessed in spite of SCE's participation in the processes, discussions or settlement negotiations, or SCE waives its right to take part in the processes, discussion or settlement negotiations, SCE shall reimburse Seller for the penalty to the extent that (a) it was solely caused by SCE's actions or inactions as SC as described in the document entitled "NERC Reliability Standards • Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator" or other successor description or document on the CAISO website at the time of the violation; and (b) Seller can establish to SCE's reasonable satisfaction that the penalty was actually assessed against Seller by NERC and paid by Seller to NERC. If SCE took part in and agreed to the terms of settlement, SCE shall also reimburse Seller for any payment made by Seller in settlement of a claim of violation by or on behalf of NERC, to the extent that (x) the claim being settled was solely caused by SCE's actions or inactions as SC as described in the document entitled "NERC Reliability Standards • Responsibilities of the Generator Operator, Scheduling Coordinator, CAl SO, and Reliability Coordinator" or other successor description or document on the CAISO website at the time of the claim; and (y) Seller can establish to SCE's reasonable satisfaction that Seller actually made the payment to N ERC under the settlement.

ARTICLE 15 CREDIT TERMS AND MARK-TO-MARKET VALUE 15.1

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEl Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex: (i) Seller's Exposure to SCE for this Transaction shall be zero dollars ($0) and (ii) SCE's Exposure to Seller plus the Independent Amount, if any, for this Transaction shall not exceed one million six hundred thousand dollars ($1,600,000) (unless otherwise defined, capitalized terms in this Article 15 are used with the meanings ascribed to them in the Transition Collateral Annex). 15.2

Independent Amount

If Seller's Credit Rating is lower than BBB- by S&P, Baa3 by Moody's, or BBB- by Fitch, Seller shall have a Full Floating Independent Amount of the amount equal to ten percent (10%) of the market value of this Transaction. Upon the Confirmation Effective Date and until the start of the Delivery Period the term "market value" shall mean the sum of the Monthly Capacity Payments to be paid under this Transaction for the Delivery Period, and upon the start of the Delivery Period the term "market value" shall mean the sum of the Monthly Capacity Payments for the current month and all remaining months of the Delivery Period to be paid under this Transaction. 15.3

Mark-to-Market Value

For purposes of determining Exposure for this Transaction, the Parties shall calculate the Current Mark-to-Market Value of this Transaction using the following methodology. On any Calculation Date, the Current Mark-to-Market Value for this Transaction will be calculated by taking the sum of the Present Values for each remaining (full or partial) month prior to the termination of this Transaction using the equation below: Current

MAX

[tl(Mv"" -

Mark-to-Market

MVo,,) x Q, x DF""

Value

0]1 l:1'(Mlt. - MY",) x Q, x lfF';i where:

21

=

2012 CHP Energy Only UC Toll (Kern Pipeline··tinancially settled gas)

MV.., = MAX (Pa• i - G•. ! D''".• ' -.'

(1.+-, r,.,,), c

X

HB;, 0)

--CX~ 365

and: Variable n i

Pt,1 ,

I Po,1

GI.I

Go,1

HR,

Q, Tt.! c d

Description The number of forward months included in the mark-to-market calculation. A forward month. For the balance of the month of the Calculation Date, i~O. For the month following the month of the Calculation Date, i~1, etc. The weighted average of Forward Price Assessments for NP15 onpeak and off peak power for the relevant forward month i on the Calculation Date. If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price calculated from tneForward-PficeAssessmenls forI'JPT5 on·peaK andoff-peaK power for the last available year. The weighted average of Forward Price Assessments for NP15 onpeak and off·peak power for the relevant forward month i on the Confirmation Effective Date. If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price calculated from the Forward Price Assessments for NP15 on-peak and off·peak power for the last available year. PG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub plus Henry Hub to PG&E City Gate Basis) for the relevant forward month I on the Calculation Date. If neither of the aforementioned gas prices are available, then the gas price for the relevant calendar month of the last available year shall be used. PG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub plus Henry Hub to PG&E City Gate Basis) for the relevant forward month i on the Confirmation Effective Date. If neither of the aforementioned gas prices are available, then the gas price for the relevant calendar month of the last available year shall be used. The Heat Rate associated with the Contract Capacity as specified in Appendix 5.3 of this Confimnation. The Contract Capacity multiplied by the hours remaining under the Transaction for the relevant forward month Interest rate (annualized) Number of compounds per year (e.g. c ~ 12 if i

~

Units

i

I

$/MWh

$/MWh

$/MMBtu

$/MMBtu

MMBtu/MWh MW * Hours %

monthly)

Number of days between calculation date (t ) and payment date.

A positive Current Mark to Market Value implies SCE has the potential for realization of market gains and thus has Exposure to Seller's default or non-performance. Notwithstanding anything to the contrary contained in the Transition Collateral Annex or this Confirmation, the Parties shall determine the Settlement Amount for this Transaction in accordance with Section 5.2 of the Master Agreement.

ARTICLE 16 ASSIGNMENT In the event of an Assignment permitted under Section 10.5 of the Transition Master Agreement, (i) any such assignee shall agree in writing to be bound by the terms and conditions hereof, (ii) the Collateral Threshold for

22

,

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

such assignee shall automatically be deemed to be zero unless the non-assigning Party otherwise agrees, and (iii) the transferring Party must deliver such tax and enforceability assurance as the non-assigning Party may reasonably request. Any assignment in violation of this Article 16 shall be null and void.

ARTICLE 17 CONFIDENTIALITY In addition to the Parties’ obligations under Section 10.11 of the Transition Master Agreement, with respect to this Transaction, Seller agrees that any data, information, or other material Seller receives from SCE or the CAISO pursuant to or in connection with this Confirmation, including any schedules, bids, awards, dispatches, Dispatch Notices, updated Dispatch Notices, settlement statements, Ancillary Services dispatches or awards, or any other information related to the Product (collectively, "Dispatch Data"), shall be confidential to SCE, and Seller shall use such Dispatch Data or other confidential information or material solely in connection with its performance of its obligations under this Confirmation and for no other purpose. Furthermore, Seller shall not disclose this Dispatch Data or other confidential information to any of its employees, personnel, contractors, agents, or consultants who are engaged wholly or in part in the business of marketing or selling wholesale electrical power or natural gas unless such employees, personnel, contractors, agents, or consultants (a) are directly engaged in performing Seller's obligations under this Confirmation, (b) need to know such information in order to perform Seller's obligations under this Confirmation, (c) are informed of (i) the confidentiality of such Dispatch Data and any information governed by this Article 17 and Section 10.11 of the Transition Master Agreement and (ii) the requirements of this Confirmation and the Transition Master Agreement, and (d) are directed to comply with the requirements of this Confirmation and the Transition Master Agreement. Seller agrees that irreparable damage to SCE would occur if Seller were to breach its obligations under this Article 17 and that SCE shall be entitled to all available remedies at law or in equity.

ARTICLE 18 PAYMENT, NETTING AND SETOFF Unless otherwise set forth herein, the Parties agree that Sections 5.3, 5.6, and Article Six of the Transition Master Agreement shall apply to this Transaction and that any payment due to or due from either Party to the other Party pursuant to the terms of this Confirmation shall be subject to such provisions.

ARTICLE 19 CALIFORNIA AIR RESOURCES BOARD REPORTING REQUIREMENTS During the Term, Seller shall provide such information SCE deems necessary for SCE to comply with those GHG emissions reporting requirements adopted by the California Air Resources Board (“CARB”), or as Seller is otherwise required to provide by Applicable Law or Governmental Authority.

ARTICLE 20 ENVIRONMENTAL CHARGES 20.1

Indemnification

Seller is solely responsible for all Environmental Costs and, other than as provided in Sections 20.2 through 20.4, all GHG Charges, Seller’s Compliance Obligation, and all other costs associated with the implementation and regulation of Greenhouse Gas emissions (whether in accordance with AB 32 or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions implemented and regulated by an authorized Governmental Authority) with respect to the Generating Unit(s) and/or Seller. Seller shall indemnify, defend and

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hold SCE harmless from and against all liabilities, damages, claims, losses, costs and/or expenses (including, without limitation, attorneys’ fees) incurred by or brought against SCE in connection with such Environmental Costs, GHG Charges, Compliance Obligation, and such other costs. 20.2

Greenhouse Gas Emissions Compliance Cost

Notwithstanding anything to the contrary in Section 20.1, and subject to Seller’s compliance with Section 20.3, in the event that a Governmental Authority imposes any taxes, charges, or fees on the Generating Unit(s) or Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (collectively, “GHG Charges”), Seller shall provide SCE documentation of such GHG Charges within 90 days of Seller incurring the obligation to pay the GHG Charge and such documentation shall establish to SCE’s reasonable satisfaction (all such documentation identified in subsections (a)-(f) below shall be collectively referred to hereinafter as “GHG Documentation”), that: (a)

Seller is actually liable for the GHG Charges during the Delivery Period;

(b)

the Applicable Law imposing the GHG Charge was (i) not in effect or (ii) not scheduled to become effective and applicable to the Generating Unit(s) as of the Confirmation Effective Date;

(c)

the specific amount of the GHG Charges;

(d)

the GHG Charge was imposed upon Seller by an authorized Governmental Authority in whose jurisdiction the Generating Units are located, or which otherwise has jurisdiction over Seller or the Generating Units;

(e)

Seller has paid the Governmental Authority identified in (d) above the full amount of the GHG Charge for which Seller seeks reimbursement from SCE under this Section 20.2; and

(f)

Seller took all reasonable steps to mitigate the cost or amount of such GHG Charges, including utilizing any GHG Credits or revenues described in Section 20.3(a)(i) below; provided, that the reasonable steps shall not be deemed to require Seller to make capital improvements to the Generating Unit.

SCE shall reimburse Seller for such GHG Charge within forty-five (45) calendar days of SCE’s receipt of the GHG Documentation. In no event shall SCE be responsible for GHG Charges associated with Greenhouse Gas emissions that exceed the GHG Cap or a Non-SCE Dispatch during the Term. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period. 20.3

Greenhouse Gas Emissions Credits (a)

In the event that, during the Term, Seller is: (i)

allocated or issued, or has the right to obtain, at no cost to Seller other than administrative or overhead costs, allowances, credits, or other similar rights to emit Greenhouse Gas in accordance with a cap-and-trade or any other federal, state or local legislation, other than AB 32, implemented by an authorized Governmental Authority (“GHG Credits”) to offset or

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reduce any Greenhouse Gas emissions, then Seller shall obtain and utilize such allowances or credits to mitigate any GHG Charge at no cost to Buyer; (ii)

allocated or issued or has the right to obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for a portion of or its entire fleet of generating units (all or some of the generating units owned, managed, or controlled by Seller that are subject to any Greenhouse Gas legislation, regulation, law or other similar governmental action) (“Seller’s Fleet”), then Seller shall utilize a proportional amount of such allowances or credits to mitigate any GHG Charge at no cost to SCE; or

(iii)

allocated or receives revenues, whether specific to the Generating Unit(s) or Seller’s Fleet, associated with any allowance or credit allocated at no cost to Seller other than administrative or overhead costs and associated with Greenhouse Gas emissions, then Seller shall remit any such revenue or, if allocated to Seller’s Fleet, the proportional amount of such revenue, to SCE to mitigate any GHG Charge.

For purposes of Section 20.3(a)(ii) and (a)(iii) above, the proportional amount of allowances, credits, or revenues, as applicable, shall be calculated based on the method, formula or other similar calculation by which the Governmental Authority used to determine the amount of GHG Credits (“GHG Calculation”) attributable to each Generating Unit compared to the sum of all GHG Calculations for all generating units within Seller’s Fleet. (b)

In the event (i) Seller is not allocated, issued, or granted the right to otherwise obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for the Generating Units pursuant to Section 20.3(a) above; (ii) Seller is not allocated or issued sufficient GHG Credits to offset GHG Charges attributable to the Generating Units; or (iii) a liquid market for GHG Credits develops and is available to purchase GHG Credits to offset the GHG Charges, then SCE may, at its option, either: (1) self-supply GHG Credits for the Generating Unit(s); or (2) provide Notice to Seller directing Seller to purchase GHG Credits sufficient to cover the GHG Charges associated with the Generating Unit(s). If SCE elects to direct Seller to purchase GHG Credits, Seller shall purchase the number of GHG Credits set forth in the Notice and SCE shall reimburse Seller for those GHG Credits at the lower of Seller’s cost or the prevailing market price at the time the GHG Credits were obtained. In no event shall either Party purchase GHG Credits from an Affiliate.

(c)

All GHG Credits (i) allocated, issued or granted, at no cost to Seller other than administrative or overhead costs, rights to Seller for the Generating Units or (ii) paid for or utilized by SCE shall be the sole and exclusive property of SCE; and any excess GHG Credits (GHG Credits not utilized by SCE under this Confirmation) or revenues resulting from GHG Credits shall be the sole and exclusive property of SCE and shall be retained by SCE.

For purposes of this Section 20.3, all references to “Seller” shall be deemed to include Seller’s parent company, holding company or other entity to which allowances or credits may be or have been allocated to or given rights to obtain, at no cost to such entity other than administrative or overhead costs, for the Generating Units. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period.

20.4

Compensation for Seller’s Compliance Obligation

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(a)

(b)

If Seller is not eligible for an exemption and subject to Section 20.5, Buyer shall satisfy its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period, in arrears of the creation of such Compliance Obligation, by: (i)

Providing to Seller the Allowances and/or the Offset Credits that will permit Seller to satisfy the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, as further described in Section 20.4(b);

(ii)

Paying to Seller the GHG Compliance Costs for the Delivery Period, as further described in Section 20.4(c); or

(iii)

Utilizing any combination of the compensation methods described in Sections 20.4(b) and 20.4(c), such that Buyer shall fulfill its obligation to compensate Seller for the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period by providing Allowances, Offset Credits and/or the GHG Compliance Costs.

If Buyer, in its sole discretion, elects to provide Seller with Allowances and/or Offset Credits, then Buyer shall, at any time (or from time to time) after Buyer has received the data for calculating the Required Natural Gas Quantity that allows Buyer to calculate Seller’s compensation for any portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, and pursuant to one or more conveyances of Allowances and/or Offset Credits, convey and deliver to Seller, either electronically or otherwise, such Allowances and/or Offset Credits; provided that: (i)

Buyer must transfer such Allowances and/or Offset Credits in a timely manner so as to permit Seller to satisfy the Compliance Obligation imposed on Seller during the Delivery Period (including, without limitation, Seller’s annual compliance obligation, as described in Section 95855 of the GHG Regulations);

(ii)

Upon each conveyance and delivery of such Allowances and/or Offset Credits by Buyer to Seller, Seller shall take all actions to accept delivery of such Allowances and/or Offset Credits such that the conveyed Allowances and/or Offset Credits shall have transferred from Buyer’s account to Seller’s account in accordance with the GHG Regulations;

(iii)

Buyer may, in its sole discretion, reduce the number of Allowances it delivers to Seller pursuant to this Section 20.4(b) by some or all of the Free Allowances that are deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s) and to the extent not applied to a prior conveyance and delivery of Allowances by Buyer to Seller under this Confirmation;

(iv)

The amount of Offset Credits that Buyer conveys and delivers to Seller throughout the Delivery Period (if any) will not exceed the Quantitative Usage Limit for the total Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period; and

(v)

No later than three (3) Business Days before Buyer conveys and delivers such Allowances and/or Offset Credits to Seller, and also on each of Transfer Date 1, Transfer Date 2 and Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period), Buyer shall deliver a notice to Seller (the “Transfer Notice”), which Transfer Notice shall inform Seller of: (1)

The number of Allowances and/or Offset Credits that Buyer has conveyed and delivered to Seller pursuant to any previous Transfer Notices, and the time-period

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during the Delivery Period for which such Allowances and/or Offset Credits applied;

(c)

(2)

The number of Allowances and/or Offset Credits that Buyer shall convey and deliver to Seller pursuant to the subject Transfer Notice, and the time-period during the Delivery Period for which such Allowances and/or Offset Credits shall apply;

(3)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Transfer Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(4)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Transfer Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(5)

The date on which Buyer shall convey and deliver such Allowances and/or Offset Credits pursuant to the subject Transfer Notice;

(6)

The number of Free Allowances deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s), which Buyer shall deduct from Buyer’s compensation of Seller to the extent such Free Allowances have not been applied to a prior conveyance and delivery of Allowances by Buyer to Seller pursuant to a Transfer Notice under this Confirmation; and

(7)

The information set forth in Section 20.4(c)(i) through (vi), if Buyer has determined to compensate Seller in part by paying to Seller the GHG Compliance Costs in accordance with Section 20.4(c).

If Buyer, in its sole discretion, elects to compensate Seller by paying to Seller the GHG Compliance Costs, then Buyer (x) shall deliver a notice to Seller on or before Transfer Date 1, Transfer Date 2 and/or Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period) (such notice, the “Required Payment Notice”), and (y) may, in its sole discretion, deliver a notice to Seller on or before any Optional Transfer Date (such notice, the “Optional Payment Notice”), which Required Payment Notice and Optional Payment Notice shall inform Seller of: (i)

Buyer’s intent to pay to Seller such GHG Compliances Costs;

(ii)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Required Payment Notices and Optional Payment Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(iii)

The time-period during the Delivery Period for which Buyer has compensated Seller pursuant to any previous Required Payment Notices or Optional Payment Notices;

(iv)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(v)

The time-period during the Delivery Period for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice; and

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(vi)

The date of the upcoming Auction pursuant to which the Auction Settlement Price necessary to calculate the GHG Compliance Costs will be based.

After (1) Seller receives such Required Payment Notice or Optional Payment Notice, and (2) the Auction Settlement Price necessary to calculate such GHG Compliance Costs is published, Seller shall calculate and include as part of the upcoming single regular monthly invoice to Buyer under this Confirmation (and in no event as an invoice that is separate or distinct from such regular monthly invoice), such GHG Compliance Costs. After Buyer’s receipt of such invoice, Buyer shall pay such GHG Compliance Costs along with all other payments due under such invoice in accordance with Article 6 of the Transition Master Agreement. (d)

Seller shall deliver to Buyer a Free Allowance Notice within twenty (20) calendar days of Seller or the Generating Unit(s) being allocated any Free Allowances (with such allocation being determined in accordance with the requirements of subparagraphs (i) or (iv) of the definition of Free Allowance Notice, as applicable, including, without limitation, the requirement that some or all of an allocation of Free Allowances to Seller’s Affiliates shall, if applicable, be deemed to be allocated to Seller). Notwithstanding anything to the contrary set forth in this Section 20.4, to the extent not previously applied, Buyer shall have the right to apply such Free Allowances or the value thereof (as disclosed in the Free Allowance Notice(s)), as applicable, in order to reduce Buyer’s compensation of Seller pursuant to Section 20.4(b) and/or Section 20.4(c) at any time during the Term regardless of when such Free Allowances are allocated (or deemed allocated) to Seller.

(e)

Seller acknowledges and agrees that: (i)

Upon Buyer’s conveyance and delivery of Allowances and/or Offset Credits in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)) or Buyer’s payment to Seller of the GHG Compliance Costs in accordance with Section 20.4(c), or any combination thereof, Buyer shall have fulfilled its obligation under this Confirmation to compensate Seller for the Compliance Obligation deemed imposed on Seller with respect to the Generating Unit(s) during the applicable time-periods set forth in the Transfer Notice(s), Required Payment Notice(s) and/or Optional Payment Notices, and that Buyer is not in any way liable for Seller’s failure to satisfy its Compliance Obligation or otherwise comply with AB 32 or the GHG Regulations; and

(ii)

Title to, and risk of loss, invalidation, cancellation or removal of each Allowance and/or Offset Credit conveyed and delivered to Seller by Buyer (including, without limitation, any such loss, invalidation, cancellation or removal of an Allowance and/or Offset Credit as a result of an action by an authorized Governmental Authority in accordance with the GHG Regulations) transfers from Buyer to Seller upon Buyer’s conveyance and delivery to Seller of each such Allowance and/or Offset Credit in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)); provided that, if (1) any Offset Credits transferred by Buyer to Seller are invalidated pursuant to the GHG Regulations after the date of such transfer, (2) Seller has not sold or otherwise transferred such Offset Credits to a third party, other than to the Governmental Authority or other entity authorized to implement the regulatory program on behalf of the Governmental Authority in satisfaction of Seller’s compliance obligation (a “Compliance Transfer”), and (3) except in the case of a Compliance Transfer, Seller demonstrates to Buyer’s reasonable satisfaction that it retains title to such invalidated Offset Credits, then to the extent such Offset Credits or other compliance instruments are still required in order for Seller to satisfy the original compliance obligation for which the Offset Credits were transferred by Buyer to Seller, Buyer shall compensate Seller in accordance with and subject to Sections 20.4 through

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20.9 for such invalidated Offset Credits to the extent necessary for Buyer to have satisfied, with respect to such invalidated Offset Credits, its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period. 20.5

Limitation of Liability

Notwithstanding anything to the contrary in the Agreement, Buyer is not responsible for:

20.6

20.7

(a)

Any Compliance Obligation imposed on Seller or the Generating Unit(s), providing any Allowances and/or Offset Credits, or paying any GHG Compliance Costs, to the extent any or all of the aforementioned are associated with Greenhouse Gas emissions that exceed the GHG Cap, that occur outside of the Delivery Period, and/or that result from a Non-SCE Dispatch;

(b)

Any taxes, fees and/or other charges implemented by and imposed upon Seller or the Generating Unit(s) pursuant to Title 17 of the California Code of Regulations, Section 95200, et. seq. (AB 32 Cost of Implementation Fee Regulation), or any similar taxes, charges and/or fees imposed on the Generating Unit(s) or Seller; or

(c)

Any taxes, fees, charges and/or other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to any generating unit that is not a Generating Unit.

Greenhouse Gas Compliance Covenants (a)

Seller covenants that (i) from the commencement of the Delivery Period until the end of the Term, it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation and (ii) throughout the Term, it shall comply with all requirements applicable to Seller and/or the Generating Unit(s) under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation.

(b)

Buyer covenants that (i) from the commencement of the Delivery Period until the end of the Term it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation, (ii) throughout the Term, it shall comply with all requirements applicable to Buyer under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation, (iii) it shall convey and deliver the Allowances and/or Offset Credits to Seller free from all liens, claims, security interests and defects in title, (iv) each Allowance and/or Offset Credit conveyed and delivered to Seller pursuant to this Confirmation (1) will be, at the time it is conveyed and delivered, validly issued and in force in accordance with the GHG Regulations, and will have been assigned a Vintage Year (as defined in the GHG Regulations) that allows it to be retired during the applicable Compliance Period in accordance with the GHG Regulations, and (2) may be utilized by Seller for compliance with AB 32 and/or the GHG Regulations then in effect, (v) it will have, at the time conveyed and delivered good and marketable title to each Allowance and/or Offset Credit conveyed and delivered to Seller, and that it will obtain and possess at the time conveyed and delivered, each such Allowance and/or Offset Credit lawfully.

Liquid Market for Allowances

If, at any time before the expiration of the Delivery Period, a liquid market for Allowances develops wherein price quotes for Allowances can be obtained, the Parties agree to work in good faith to amend this Confirmation to include a methodology for calculating the GHG Compliance Costs for this Transaction using such price quotes. 20.8

Suspension, Repeal or Supersedence of AB 32; Change in AB 32

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Notwithstanding anything to the contrary in the Agreement, if AB 32 is suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then, as of the effective date of such suspension, repeal or supersedence, Sections 20.4 through 20.8 will no longer be in force or effect on a going forward basis; provided that subject to and in accordance the terms of the Agreement, Buyer shall be liable to Seller for compensating Seller for Seller’s Compliance Obligation, if any, imposed on Seller for the Generating Unit(s) before such suspension, repeal or supersedence. To the extent Buyer has provided compensation to Seller pursuant to Sections 20.4(b) and 20.4(c) to cover an expected Compliance Obligation under AB 32 and that obligation is subsequently suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then Seller shall return any such compensation in a timely manner to Buyer. If a Change in AB 32 occurs, then either Party, on notice, may request the other Party to enter into negotiations to make the minimum changes to this Confirmation necessary to preserve to the maximum extent possible the balance of benefits, burdens and obligations set forth in this Confirmation as of the Confirmation Effective Date. Upon receipt of a notice requesting negotiations, the Parties shall negotiate in good faith. If the Parties are unable, within sixty (60) days after the sending of the notice requesting negotiations, either to agree upon changes to this Confirmation or to resolve issues relating to changes to this Confirmation, then either Party may submit issues pertaining to changes to this Confirmation to dispute resolution as provided in Section 10.6 of the Transition Master Agreement. In addition to any notices provided above, Seller shall provide notice to SCE as soon as practicable in the event that Seller believes a Change in AB 32 has occurred. 20.9

Exposure Calculation (a)

Subject to any restrictions set forth in the Agreement (including, without limitation, Section 15.1 and Section 20.5 of this Confirmation), the Parties agree that for purposes of calculating Seller’s Exposure to Buyer in respect of a Transaction under the Confirmation, such calculation shall include Buyer’s obligation to compensate Seller for the Compliance Obligation imposed on Seller for the Generating Unit(s) during the Delivery Period to the extent that such obligation is owed or otherwise accrued and payable (regardless of whether such amounts have been or could be invoiced) to Seller and remains unpaid as of the Calculation Date.

(b)

Seller’s Exposure to Buyer in respect of a Transaction under this Confirmation shall be calculated by multiplying (i) the most recent published ICE OTC Physical Environmental Settlements CCA Index Price for the appropriate vintage (e.g., Dec 2013, Dec 2014) immediately preceding the Calculation Date by (ii) the number of metric tons of Greenhouse Gas emitted by and attributable to the Generating Unit(s) for which Buyer has not compensated Seller pursuant to the Confirmation, with such number to be determined in accordance with subparagraph (ii) of the definition of GHG Compliance Costs (rounded up to the nearest metric ton) set forth in the Confirmation.

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APPENDIX A DEFINITIONS UNLESS OTHERWISE DEFINED IN THE TRANSITION MASTER AGREEMENT AND ATTACHMENTS, CAPITALIZED TERMS SHALL BE USED WITH THE MEANINGS ASCRIBED TO THEM IN THE TARIFF. AB 32: The California Global Warming Act of 2006, Assembly Bill 32 (2006) and the regulations promulgated thereunder (including, without limitation, the GHG Regulations) by any authorized Governmental Authority. Accepted Electrical Practices: Those practices, methods, applicable codes, and acts engaged in or approved by a significant portion of the electric power industry during the relevant time period, or any of the practices, methods, and acts which, in exercise of reasonable judgment in light of the facts known at the time a decision is made, could have been expected to accomplish a desired result at reasonable cost consistent with good business practices, reliability, safety, and expedition. Accepted Electrical Practices are not intended to be limited to the optimum practices, methods, or acts to the exclusion of other, but rather to those practices, methods, and acts generally accepted, or approved by a significant portion of the electric power industry in the relevant region, during the relevant time period, as described in the immediately preceding sentence. Adjustment Gas Cost: As set forth in Section 3.1(d)(viii) of this Confirmation. Adjustment Gas Quantity: As set forth in Section 3.1(d)(v) of this Confirmation. ADS: The Automatic Dispatch System, or its successor. Air Pollution Control District: A district as defined by Section 39025 of the California Health and Safety Code, Division 26, Air Resources. Allowance: (i) CA GHG Allowance, as such term is defined in the GHG Regulations, or (ii) an allowance specified in Section 95942(b) of the GHG Regulations and approved by the CARB pursuant to Section 95941 of the GHG Regulations. Ancillary Services: As set forth in the Tariff. Ancillary Services Capacity: For each applicable Ancillary Service, the Ancillary Service available to SCE within the scope of operations allowed SCE under this Confirmation pursuant to Section F of Appendix 1.4, plus any other interconnected operation services that the CAISO develops or deems as Ancillary Services. Applicable Laws: Means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Authority having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. A/S Availability: The amount of Ancillary Services Capacity available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. A/S Maximum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the maximum capacity for a particular region in which such Ancillary Service is available. A/S Minimum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the minimum capacity for a particular region in which such Ancillary Service is available.

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Auction: Each auction for Allowances conducted in accordance with Subarticle 10 of the GHG Regulations, except for the first auction identified in Section 95910(a)(1) of the GHG Regulations. Auction Settlement Price: As set forth in the GHG Regulations. Automatic Generation Control or AGC: output.

The remote signal control of a Generating Unit’s megawatt

Availability Incentive Payments: As set forth in the Tariff. Availability Notice: As set forth in Section 9.1 of this Confirmation. Availability Standards: As set forth in the Tariff. Available Capacity: The amount of Contract Capacity that is available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. If a Generating Unit’s Available Capacity during any Settlement Interval is below PMin, then the Available Capacity shall be deemed zero for such Settlement Interval. Black Start: As set forth in the Tariff. Boiler or Boiler Unit: Conventional steam cycle. CAISO: The California Independent System Operator or any successor entity performing the same functions. CAISO Grid: The system of transmission lines and associated facilities of the Participating Transmission Owners that have been placed under the CAISO’s operational control. Capacity: Exclusive of any Resource Adequacy Benefits, the maximum dependable operating capability of any generating resource to produce or generate Energy and any other products that may be developed or evolve from time to time that relate to the capability of a generating resource to produce or generate Energy. Capacity Availability: For each Settlement Interval (i) the Generating Unit’s Available Capacity, if the Generating Unit operates within the Performance Tolerance Band, or (ii) the Generating Unit’s Available Capacity, less the product of (x) the difference between (a) Scheduled Energy minus (b) Qualifying Delivered Energy, and (y) the number of Settlement Intervals in one hour, if the Generating Unit operates below the Performance Tolerance Band Lower Limit. In no event shall the Capacity Availability be less than zero MW nor greater than the Contract Capacity for the Generating Unit. CARB: California Air Resources Board, or any successor entity. CCGT: Combined cycle gas turbine. Change in AB 32: A change in AB 32 after the Confirmation Effective Date, which change has a material impact on either party with respect to a Compliance Obligation under Article 20 with respect to the electric energy produced, sold or purchased pursuant to this Confirmation. A Change in AB 32 may include, for example, a change in exemptions or the calculation of compliance obligations, but will not include an increase or decrease in the cost of Allowances or Offset Credits. CHP: As set forth in Article 5 of this Confirmation. Compliance Obligation: As set forth in the GHG Regulations.

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Compliance Period: As set forth in the GHG Regulations. Compliance Transfer: As set forth in Section 20.4(e)(ii) of this Confirmation. Contract Capacity: As set forth in Section A of Appendix 1.4 of this Confirmation, the Quantity of Capacity that Seller is committing to provide to SCE pursuant to this Confirmation. Contract Year: The twelve (12) months within each calendar year starting with the beginning of the Delivery Period until the termination of this Confirmation. CPUC: The California Public Utilities Commission or any successor thereto. CPUC Approval: Means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of this Confirmation, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. Crossing Time: Forbidden Region Crossing Time, as set forth in the “Definition” tab of the CAISO Master File. CT: Combustion turbine. Day-Ahead Gas Cost: As set forth in Section 3.1(d)(vii) of this Confirmation. Day-Ahead Gas Quantity: As set forth in Section 3.1(d)(iv) of this Confirmation. Delivered Energy: With respect to a Generating Unit and during the Delivery Period, the amount of Energy generated by such Generating Unit and delivered during each Settlement Interval at the Energy Delivery Point as measured by the Energy Metering Equipment, and subject to adjustments identified in this Confirmation. The Delivered Energy in any hour is equal to the sum of the Delivered Energy for each Settlement Interval during such hour. Delivery Period: Has the meaning specified in Section 1.4 of this Confirmation. Delivery Period End Date: Has the meaning specified in Section 1.4 of this Confirmation. Disclosure Schedule: As set forth in Section 13.3(c) of this Confirmation. Dispatch Data: As set forth in Article 17 of this Confirmation. Dispatch Notice: The operating instruction, and any subsequent updates given by SCE to Seller, directing the applicable Generating Unit to operate at a specified megawatt output or a dispatch given by the CAISO under Section 9.3. Dispatch Notices may be communicated electronically (i.e., through ADS), via e-mail, via facsimile, telephonically, or by other verbal means. Telephonic or other verbal communications shall be documented (either recorded by tape, electronically or in writing) and such recordings shall be made available to both SCE and Seller upon request for settlement purposes. Distributed Control System or DCS: The integrated automation system for monitoring and controlling the critical operation functions of a facility that performs tasks essential to the generation of electricity. Emission Reduction Credits or ERC(s): Emission reductions that have been authorized by a local air

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pollution control district pursuant to California Division 26 Air Resources; Health and Safety Code Sections 40709 and 40709.5, whereby a district has established a system by which all reductions in the emission of air contaminants that are to be used to offset certain future increases in the emission of air contaminants shall be banked prior to use to offset future increases in emissions. Energy: All electrical energy produced, flowing, or supplied by a Generating Unit less the Station Use, measured in kilowatt-hours or multiples units thereof. Energy shall include without limitation any energy associated with Capacity, Ancillary Services, and any other electrical energy product that may be developed or evolve from time to time during the Term. Energy Delivery Point: The point on the CAISO grid defined in Appendix 1.6 of this Confirmation. Energy Metering Equipment: For each Generating Unit, the meters and measuring equipment certified by the CAISO for such Generating Unit, and which measures the Delivered Energy of such Generating Unit. Environmental Costs: Costs incurred in connection with acquiring and maintaining all environmental permits and licenses for the Generating Units, and the Generating Unit’s compliance with all applicable environmental laws, rules and regulations, including capital costs for pollution mitigation or installation of emissions control equipment required to permit or license the Generating Units, all operating and maintenance costs for operation of pollution mitigation or control equipment, costs of permit maintenance fees and emission fees as applicable, and the costs of all Emission Reduction Credits or Marketable Emission Trading Credits required by any applicable environmental laws, rules, regulations, and permits to operate, and costs associated with the disposal and clean-up of hazardous substances introduced to the Generating Unit site, and the decontamination or remediation, on or off the Generating Unit site, necessitated by the introduction of such hazardous substances on the Generating Unit site. Exposure: As set forth in the Transition Collateral Annex. Failed Test: As set forth in Section 10.2 of this Confirmation. FERC Approval: Means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at marketbased rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. Final Test Plan: As set forth in Appendix 10.2 of this Confirmation. Forbidden Operating Region: As set forth in the Tariff. Forced Outage: As set forth in the Tariff. Free Allowance: Authority.

Any Allowance freely allocated by the CARB or another authorized Governmental

Free Allowance Notice: The notice delivered by Seller to Buyer in accordance with Section 20.4(d), which notice shall set forth:

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(i) The aggregate quantity of Free Allowances allocated by the CARB (and/or any other Governmental Authority) to Seller, any of Seller’s Affiliates, and/or the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof); and (ii) Any documentation from the CARB (and/or any other Governmental Authority) relating to such allocation. If the CARB (and/or any other Governmental Authority) allocates Free Allowances to Seller (and/or any of Seller’s Affiliates), but does not specifically allocate such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), then the notice described in this definition shall set forth: (iii) The aggregate quantity of Free Allowances allocated to Seller and/or any of Seller’s Affiliates by the CARB (and/or any other Governmental Authority), and all documentation from the CARB (and/or any other Governmental Authority) relating to such allocation; (iv) The number of Free Allowances that shall be deemed allocated to Seller and/or the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), which number Seller shall calculate: (1) By utilizing the then-effective methodology established by the CARB (and/or any other Governmental Authority) relating to such allocation, including, without limitation, any methodology that would apportion a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, Covered Entities and/or Opt-in Covered Entities (as each term is defined in the GHG Regulations)) that could be allocated such Free Allowances; or (2) If the CARB (and/or other Governmental Authority) has not established such a methodology, by apportioning a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, oil refineries and/or other industrial process plants) that could be allocated such Free Allowances; and (v) All documentation reasonably necessary to support the methodology set forth in subparagraph (iv)(1) and/or (iv)(2) of this definition, which shall include, without limitation, any documentation reasonably requested by Buyer to verify Seller's methodology and calculations after Buyer’s receipt of such notice. Fuel Payment: As set forth in Section 3.1(d) of this Confirmation. Full Floating Independent Amount: As set forth in Section 15.2 of this Confirmation. Full Load: As set forth in Appendix 10.2 of this Confirmation. GADS: The Generating Availability Data System, or its successor. Gas Commodity Costs: As set forth in Section 3.1(d)(vi) of this Confirmation. Gas Day: As defined in the applicable tariff of the gas transporter supplying the Generating Unit. Gas Index: As defined in Section 3.1(d)(i) of this Confirmation.

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Gas Trading Day: As set forth in Section 3.1(d)(ii) of this Confirmation. Generating Facility: Power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. The Generating Facility shall include the Generating Units. Generating Unit: The generating unit or units specified in Appendix 1.8 of this Confirmation. References to Generating Units shall be applicable only to Generating Unit # 2 and Generating Unit #4 throughout the Delivery Period. Generating Unit # 2: The Generating Unit described in Section 1.a. of Appendix 1.8 of this Confirmation. Generating Unit # 4: The Generating Unit described in Section 1.b. of Appendix 1.8 of this Confirmation. Generation Operations Center or GOC: The location of SCE’s Real Time operations personnel. Generation Management System or GMS: The automated system employed by SCE real time operations to remotely monitor, dispatch, and control each Generating Unit. Generator Operator: The entity that operates the Generating Unit(s) and performs the functions of supplying energy and interconnected operations services as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. Generator Owner: The entity that owns and maintains the Generating Unit(s) as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. GHG Calculation: As set forth in Section 20.3 of this Confirmation. GHG Cap: The GHG Rate times the Required Natural Gas Quantity associated with a Dispatch Notice. GHG Charges: As set forth in Section 20.2 of this Confirmation. GHG Compliance Cost: The dollar amount calculated by multiplying: (i) The cost of one Allowance, determined using the published Auction Settlement Price from the last Auction to have taken place before the date that Buyer’s payment is due to Seller in accordance with Section 20.4(c); by (ii) The number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) during the applicable time-period, which number is determined by multiplying the GHG Rate by the Required Natural Gas Quantity for each calendar day during the applicable time-period; provided that if Buyer determines to compensate Seller for a portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) by providing Seller with Allowances and/or Offset Credits in accordance with Section 20.4(b), the factor set forth in this subparagraph (ii) will be reduced by the number of metric tons of Greenhouse Gas emissions (rounded up to the nearest metric ton) for which Buyer provides such Allowances and/or Offset Credits. GHG Credits: As set forth in Section 20.3(a)(i) of this Confirmation. GHG Documentation: As set forth in Section 20.2 of this Confirmation. GHG Rate: The rate for pounds of Greenhouse Gas emissions per MMBtu of natural gas, 117 lbs of Greenhouse Gas emissions /MMBtu, as derived through information provided in the Energy Information Administration’s Documentation for Emissions of Greenhouse Gases in the United States 2005 (DOE/EIA-0638) http://www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2005).pdf and the

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Environmental Protection Agency’s Emission Factors, AP 42, Fifth Edition, Volume I http://www.epa.gov/ttn/chief/ap42/index.html. GHG Regulations: Subchapter 10 Climate Change, Article 5, Sections 95800 to 96022, Title 17, California Code of Regulations, as amended or supplemented from time to time. Governmental Authority: Any federal, state, local, municipal, or other governmental, executive, administrative, judicial, or regulatory entity, and the CAISO or any other transmission authority, having or asserting jurisdiction over a Party, any Generating Unit or this Confirmation. Green Attributes: Any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1

(3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall 1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program.

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provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. Greenhouse Gas: As set forth in the GHG Regulations. Heat Rate: The amount of natural gas in MMBtu required to produce one MWh of Energy. Historical Outage Report: As set forth in Section 13.3(d) of this Confirmation. Holiday: New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, or Christmas Day. When any Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. Host Site: The site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Affiliates located at such site. IE: As set forth in Section 13.2(b) of this Confirmation. IFA or Interconnection Facilities Agreement: Any agreement between the Seller and its Participating Transmission Owner providing for the transmission of electrical energy from the Generating Unit to the point of interconnection. IFM or Integrated Forward Market: As set forth in the Tariff. Industry Standards: As set forth in Section 13.1 of this Confirmation. Lower MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Marketable Emission Trading Credits: Without limitation, emissions trading credits or units pursuant to the requirements of California Division 26 Air Resources; Health & Safety Code Section 39616 and Section 40440.2 for market based incentive programs such as the South Coast Air Quality Management District’s Regional Clean Air Incentives Market, also known as RECLAIM, and allowances of sulfur dioxide trading credits as required under Title IV of the Federal Clean Air Act (see 42 U.S.C. § 7651b.(a) to (f)). Master File: As set forth in the Tariff. Maximum Daily Start-Ups: As set forth in the Tariff. MCP or Market Clearing Price: For each Settlement Interval, the Day-Ahead Market price for the hour in which such Settlement Interval falls for the SP15 EZ Gen Hub. Minimum Down Time: As set forth in the Tariff. Minimum Load: As set forth in the Tariff. Minimum Run Time: As set forth in the Tariff. Monthly Capacity Payment: As set forth in Appendix 3.1(a), but subject to Article 3 of this Confirmation. MSA or Meter Service Agreement: Scheduling Coordinator Meter Service Agreement. Natural Gas Requirements: All of the Generating Unit’s natural gas requirements, including the Required Natural Gas Quantity, natural gas for any Non- SCE Dispatch and natural gas for any other purpose.

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NERC/GADS Protocols: The GADS protocols established by NERC, as may be updated from time to time. NERC Holidays: “Additional Off-peak Days” as defined by NERC on the NERC website at http://www.nerc.com. NERC Reliability Standards: Those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by NERC and approved by the applicable regulatory authorities and available on the NERC website. Non-Availability Charges: As set forth in the Tariff. Non-SCE Dispatch: A dispatch by Seller either (a) pursuant to a Seller Initiated Test or (b) as required by Applicable Laws. Non-Spinning Reserve: As set forth in the Tariff. Offset Credit: As set forth in the GHG Regulations. Operating Day: A day within the Delivery Period on which the Generating Unit operates. Operating Level: As set forth in the “Definition” tab of the CAISO Master File. Operating Reserve Ramp Rate: As set forth in the Tariff. Operating Restriction: Limitations on SCE’s ability to schedule and use Capacity, Ancillary Services, and Energy for each Generating Unit subject to this Confirmation that are identified in Appendix 1.4. Operational Ramp Rate: As set forth in the Tariff. Optional Payment Notice: As set forth in Section 20.4(c). Optional Transfer Date: The first (1st) Business Day of the month in which an Auction during the Delivery Period takes place, not including Transfer Date 2 or Transfer Date 3. Outage: As set for in the Tariff. Outage Management System: As set forth in Section 9.1 of this Confirmation. Outage Schedule: As set forth in Section 11.1 of this Confirmation. Pacific Prevailing Time or PPT: Pacific Daylight Time when California observes Daylight Savings Time and Pacific Standard Time otherwise. Participating Transmission Owner: A transmission owner which has released operational control of its transmission facilities to the CAISO. Performance Tolerance Band: The higher of (a) three percent (3%) of a Generating Unit’s PMax divided by the number of Settlement Intervals in an hour, (b) five (5) MW divided by the number of Settlement Intervals in an hour, or (c) the applicable Regulation Award divided by the number of Settlement Intervals in an hour. If, at any time, the CAISO implements changes to the Performance Tolerance Band, then the Parties agree to negotiate in good faith to amend this definition to maintain the economic benefits and burdens contemplated under this Confirmation. Performance Tolerance Band Lower Limit: A quantity of Energy determined for a Settlement Interval

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

equal to Scheduled Energy minus the Performance Tolerance Band. Performance Tolerance Band Upper Limit: A quantity determined for a Settlement Interval equal to Scheduled Energy plus the Performance Tolerance Band. Permit Requirements: Any requirement or limitation imposed as a condition of a permit or other authorization relating to construction or operation of the Generating Units subject to the obligations of this Confirmation or related facilities, including limitations on any pollutant emissions levels, limitations on fuel combustion or heat input throughput, limitations on operational levels or operational time, limitations on any specified operating constraint, requirements for acquisition and provision of any Emission Reduction Credits or Marketable Emission Trading Credits; or any other operational restriction or specification related to compliance with any Applicable Laws. PGA or Participating Generator Agreement: As set forth in the Tariff. Planned Outage: As set forth in the applicable CPUC Decisions, namely a planned, scheduled, or any other Outage for the routine repair or maintenance of the Generating Units, or for the purposes of new construction work, and does not include any Outage designated as either forced or unplanned as defined by the CAISO or NERC/GADS Protocols. PMax: As defined in the Tariff. The value of PMax is specified in Appendix 1.4 of this Confirmation. PMin: Minimum Load. Power Rating: The electrical power output value indicated on the generating equipment nameplate. Present Value: The value on a given date of a future payment or series of future payments, discounted using the appropriate yield curve based on the U.S. Treasury constant maturities securities as posted by the Federal Reserve in their H.15 daily update at the following address: http://www.ustreas.gov/offices/domestic-finance/debt-management/interest-rate/yield.html. Product: As set forth in Section 1.5 of this Confirmation. Project: The Generating Facility. Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Protective Apparatus: The control devices (such as meters, relays, power circuit breakers and synchronizers) specified in the Interconnection Facilities Agreement for the Generating Unit. PTC 22: The performance test code entitled “PTC-22-2005 - Gas Turbines," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PTC 46: The performance test code entitled “PTC 46-1996 - Overall Plant Performance," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PURPA: The Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. Qualifying Delivered Energy: The lesser of Delivered Energy or the Performance Tolerance Band Upper Limit for each Settlement Interval during the Delivery Period. Qualifying Delivered Energy shall be zero (0) (i) during a Seller Initiated Test; (ii) during a Non-SCE Dispatch; (iii) if the Delivered Energy is less than PMin minus the Performance Tolerance Band; or (iv) during a Start-Up.

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Qualifying Facility: An electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of self-certification pursuant to 18 CFR Part 292.207(a). Quantitative Usage Limit: As set forth in the GHG Regulations. Reduced Monthly Capacity Payment: As set forth in Section 3.2(c) of this Confirmation. Regulation Award: For each Settlement Interval, shall mean either (i) with respect to the Performance Tolerance Band Upper Limit, the greater of the fifteen-minute HASP Regulation Up awards for the period within such Settlement Interval falls, or (ii) with respect to the Performance Tolerance Band Lower Limit, the greater of the fifteen-minute HASP Regulation Down awards for the period within such Settlement Interval falls. Regulation Down: As set forth in the Tariff. Regulation Ramp Rate: As set forth in the Tariff. Regulation Up: As set forth in the Tariff. Renewable Energy Credit: As set forth in Public Utilities Code Section 399.12(h), as may be amended from time to time or as further defined or supplemented by applicable law. Repair Plan: As set forth in Section 13.2(b) of this Confirmation. Required Natural Gas Quantity: As set forth in Section 3.1(d)(iii) of this Confirmation. Required Payment Notice: As set forth in Section 20.4(c). Resource Adequacy Benefits: The rights and privileges attached to any generating resource that satisfy any entity’s resource adequacy obligations or requirements under any CPUC Decisions 04-01-050, 0410-035, 05-10-042, 06-04-040, 06-06-064, 06-07-031, and 07-06-029 and/or any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable Governmental Authority, as such decisions, rulings, laws, rules, or regulations may be amended or modified from time to time. Resource Adequacy Resource: As set forth in the Tariff. RFO Agreement: The Master Power Purchase and Sale Confirmation Letter (Energy Only UC Toll (Kern Pipeline—financially settled gas)) between the Parties, dated July 2, 2012, as may be amended from time to time. RMR Settlement Coordinator: As set forth in Section 7.2 of this Confirmation. RMR Invoice: As set forth in Section 7.2 of this Confirmation. RMR Revenue: As set forth in Section 7.2 of this Confirmation. Satellite Communications System or SCS: A system provided to Seller by SCE at SCE’s cost for emergency voice communications between SCE and Seller’s operating staff for the Generating Units. SCE Annual Test: As set forth in Section 10.2 of this Confirmation.

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SCE Dispatched Test: As set forth in Section 10.1 of this Confirmation. SCE Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Scheduled Energy: The Energy from a Generating Unit expected to be delivered during each Settlement Interval to the Energy Delivery Point pursuant to (a) the latest Dispatch Notice, or (b) any CAISO instructions during the Delivery Period, including (i) supplemental energy bids or (ii) Ancillary Services exercised. If, in any Settlement Interval, the expected energy normally published by CAISO is unavailable, incomplete, or does not conform to the Operating Restrictions of the Generating Units, then for settlement purposes for that Settlement Interval only, the Scheduled Energy shall be deemed to be the Delivered Energy. Scheduling Coordinator or SC: As set forth in the Tariff. SC Replacement Date: As set forth in Section 6.4 of this Confirmation. SDD Administration Charge: As set forth in Section 8.4 of this Confirmation. SDD Admin Price: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term as defined in the Tariff. SDD Charge: A scheduling and delivery deviation charge as set forth in Section 8.3 of this Confirmation. SDD Price: For each Generating Unit, the Resource-Specific Settlement Interval LMP (as defined in the MRTU's Tariff Appendix A – “Definitions”) or any equivalent price under MRTU. In no case shall the SDD Price be less than zero (0). Self-Schedule: As set forth in the Tariff. Seller Initiated Test: As set forth in Section 10.1 of this Confirmation. Seller’s Fleet: As set forth in Section 20.3(a)(ii) of this Confirmation. Seller’s Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Settlement Agreement: The Qualifying Facility and Combined Heat and Power Program Settlement Agreement approved by the CPUC in Decision 10-12-035 issued on December 21, 2010, effective November 23, 2011. Settlement Interval: As set forth in the Tariff. Shape: As set forth in Appendix 14 of this Confirmation. Shaped Price: Confirmation.

Shall be the price of power as determined in accordance with Appendix 14 of this

Site Host: The person or persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating Units and the generating units that are subject to the obligations in the Transition PPA. Site Host Load: The electric energy and capacity produced by or associated with the Generating Units and the generating units that are subject to the obligations in the Transition PPA that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b).

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Site Specific Reference Conditions: Shall have the meaning specified in Appendix 10.2 SP15: The SP15 EZ Gen Hub. If the SP15 EZ Gen Hub (under any name) is not established as part of a market redesign that is implemented after the commencement of the Term, an alternative trading zone may be mutually agreed upon by the Parties in good faith that reasonably approximates the characteristics of the Existing Zone region of SP15. SP15 EZ Gen Hub: As set forth in the Tariff. Spinning Reserve: As set forth in the Tariff. Start-Up: Resulting only from a Dispatch Notice, the action of bringing the Generating Unit from shut down status to synchronization with the grid, attainment of its PMin, and the availability of unconditional release of such Generating Unit ready for ramping to the applicable dispatch instruction. Start-Up Aux Energy: The applicable amount of energy (MWh) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Aux Charge: The product of the applicable Start-Up Aux Energy and the sum of the “energy charge” rates (under the column headers “Delivery Service” and “Generation”) set forth in PG&E Tariff Rate Schedule S for “Standby Service at Transmission Service Voltage”] applicable to the appropriate “peak” period and in effect at the time of the applicable Start-Up. If a Start-Up falls within multiple “peak” periods (on-peak, mid-peak, or off-peak), then the Start-Up Aux Charge shall be calculated by applying the applicable “energy charge” rates to the Start-Up Aux Energy amount proportional to amount of time elapsed under each applicable “peak” period. Start-Up Charge: The applicable charge ($) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Fuel: The applicable volume of natural gas (MMBtu) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Notice: As set forth in Section 9.2(b) of this Confirmation. Start-Up Time: The applicable amount of time (minutes) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Station Use: The electrical load of the Generating Unit’s auxiliary equipment. The auxiliary equipment includes forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems, control systems, and sump pumps. Substitution Cost: As set forth in Section 6.5 of this Confirmation. Substitution Rules: As set forth in Section 6.5 of this Confirmation. Successful Repair: Immediately upon completion of the repairs to a Generating Unit, Seller demonstrates, at Seller’s expense, to SCE’s reasonable satisfaction, that such Generating Unit can: (i) Start-Up and ramp up to and remain at full load for two (2) consecutive hours, and (ii) immediately thereafter remain available to generate Energy under this Confirmation by a quantity greater than or equal to ninety-eight percent (98%) of Contract Capacity for seven (7) consecutive days.

44

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Supply Plan: As set forth in the Tariff. Tariff: The tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. Term: As set forth in Section 1.3 of this Confirmation. Test Parameters: Shall have the meaning specified in Appendix 10.2 Trading Day: The day in which Day Ahead trading occurs in accordance with the WECC Preschedule Calendar. Transfer Date 1: The first (1st) Business Day of the month in which the Auction immediately following the end of the Delivery Period is to take place. Transfer Date 2: The first (1st) Business Day of the month in which the Auction immediately following the end of each year during the Delivery Period that Seller must satisfy its annual compliance obligation (as described in Section 95855 of the GHG Regulations) is to take place. Transfer Date 3: The first (1st) Business Day of the month in which the Auction immediately following the end of the applicable Compliance Period is to take place, if such Compliance Period ends during the Delivery Period. Transfer Notice: As set forth in Section 20.4(b)(v). Transmission Owner: As set forth in the Tariff. Transition PPA: As set forth in the Transition Cover Sheet. Transition RA Confirmation: That certain Resource Adequacy Confirmation dated herewith between Seller and SCE, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. Turbine Configuration: As set forth in Appendix 1.8 of this Confirmation. UDP: Uninstructed Deviation Penalty, as applied to each SC by the CAISO, or any successor thereto pursuant to the Tariff. Uninstructed Deviation GMC Rate: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term to UIE. Upper MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Variable O&M Charge: As set forth in Appendix 3.1(b) of this Confirmation. Variable O&M Payment: As set forth in Section 3.1(b) of this Confirmation. WECC Preschedule Calendar: The Preschedule Calendar(s) as set forth or described on the WECC website at http://www.wecc.biz.

45

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 1.4

46

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

CONTRACT CAPACITY, ANCILLARY SERVICES AND OPERATING RESTRICTIONS Technology:

COMBUSTION TURBINE Sycamore Cogeneration Company Unit 2

Generating Unit Name: A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information

Minimum Load, PMin (MW):

70.00

PMax (MW):

85.00

Max capacity w/o duct burners (MW):

85.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Daily Run Hours

No

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

85.00

1.00

Best Operational Minimum Down Minimum Run Ramp Rate Time (minutes): Time (minutes): (MW/min) 60.00

3.00

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Yes Ancillary Services are included: No KRCC is not currently included in Black Start Capability Plan Black Start included: Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

47

A/S Minimum Capacity(MW)

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Technology:

COMBUSTION TURBINE Sycamore Cogeneration Company Unit 4

Generating Unit Name: A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information

Minimum Load, PMin (MW):

70.00

PMax (MW):

85.00

Max capacity w/o duct burners (MW):

85.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Daily Run Hours

No

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

85.00

1.00

Best Operational Minimum Down Minimum Run Ramp Rate Time (minutes): Time (minutes): (MW/min) 60.00

3.00

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Yes Ancillary Services are included: No KRCC is not currently included in Black Start Capability Plan Black Start included: Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

48

A/S Minimum Capacity(MW)

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 1.6

49

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

ENERGY DELIVERY POINT

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 1.8 DESCRIPTION OF GENERATING UNITS AND DESCRIPTION OF SITE 1.

Generating Units Description.

a.

Generating Unit # 2 i.

Name: Sycamore Cogeneration Company Unit # 2

ii.

Location: SW China Grade Loop, Bakersfield, California

iii. CAISO Resource ID (as defined in the CAISO Tariff): As of the Confirmation Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the start of the Delivery Period, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit. iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: Unknown MW. As soon as possible, but no later than 30 days prior to the start of the Delivery Period, Seller shall provide notice to Buyer of Generating Unit NQC assigned by CAISO to this Generating Unit. v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

b.

xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 74.00

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 100886

Generating Unit # 4 i.

Name: Sycamore Cogeneration Company Unit # 4

ii.

Location: SW China Grade Loop, Bakersfield, California

iii. CAISO Resource ID (as defined in the CAISO Tariff): As of the Confirmation Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the start of

51

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

the Delivery Period, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit. iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: Unknown MW. As soon as possible, but no later than 30 days prior to the start of the Delivery Period, Seller shall provide notice to Buyer of Generating Unit NQC (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit. v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 74.00

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 100886

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

2.

Site Description. Sycamore Cogeneration Company Plant Site

PARCEL 1: That portion of that certain patented placer mining claim known as Amazon Placer Mining Claim described in the patent as the Southwest Quarter at the Southeast Quarter of Section 30, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area, County of Kern, State of California, according to the official plat thereof, which is included within the South 10 acres of the Southwest Quarter of the South east Quarter of said Section.

Except any veins or lodes of quartz or other rock in place bearing gold, silver, cinnabar, lead, tin, copper or other valuable deposits within the land above described which may have been discovered or known to exist on or prior to August 23, 1915.

PARCEL 2: The Northwest Quarter of the Northeast Quarter of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof.

PARCEL 3: The North Half of Lot 1 of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof.

53

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 3.1(a)

DELIVERY PERIOD AND MONTHLY CAPACITY PAYMENT

54

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015 $3.15 $3.15 $3.15 $3.15

Monthly Capacity Price[1] ($/kW-month)

[1] Monthly Capacity Price expressed in whole dollars and cents B. Monthly Payment Price Shape Table [2] Month 2012 2013 2014 2015 2016 January 0% 20% 20% 96% 0% February 0% 10% 10% 48% 0% March 0% 10% 10% 48% 0% April 0% 10% 10% 48% 0% May 0% 30% 30% 144% 0% June 0% 45% 45% 216% 0% July 0% 330% 330% 0% 0% August 0% 405% 405% 0% 0% September 0% 240% 240% 0% 0% October 105% 35% 35% 0% 0% November 75% 25% 25% 0% 0% December 120% 40% 40% 0% 0% [2] Price shape is determined based on the heat rate of the Generating Unit, these values are contained in the All Source RFO Instructions. C. Maximum Monthly Capacity Payment ($) Month 2012 2013 2014 2015 2016 January $ - $ 46,620.00 $ 46,620.00 $ 223,776.00 $ - $ February $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ March $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ April $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ May $ - $ 69,930.00 $ 69,930.00 $ 335,664.00 $ - $ June $ - $ 104,895.00 $ 104,895.00 $ 503,496.00 $ - $ July $ - $ 769,230.00 $ 769,230.00 $ - $ - $ August $ - $ 944,055.00 $ 944,055.00 $ - $ - $ September $ - $ 559,440.00 $ 559,440.00 $ - $ - $ October $ 244,755.00 $ 81,585.00 $ 81,585.00 $ - $ - $ November $ 174,825.00 $ 58,275.00 $ 58,275.00 $ - $ - $ December $ 279,720.00 $ 93,240.00 $ 93,240.00 $ - $ - $

Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

55

2018 $ $ $ $ $ $ $ $ $ $ $ $

2017 -

2018 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2017 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

12.000

2019

2019 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Enter Heat Rate at Pmax (MMBTU/MWh)

For the purposes of this template, figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year.

A. Monthly Capacity Price Information

Generating Unit Name: Sycamore Cogeneration Company Unit 2

-

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

$ $ $ $ $ $ $ $ $ $ $ $

2020

2020 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 2013 2014 2015

Calendar Year

-

$ $ $ $ $ $ $ $ $ $ $ $

2021

2021 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

74.00

Contract Capacity (MW)

-

$ $ $ $ $ $ $ $ $ $ $ $

2022

2022 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

2023

2023 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

Base Price Shape 20% 10% 10% 10% 30% 45% 330% 405% 240% 35% 25% 40%

2024

2024 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015 $3.15 $3.15 $3.15 $3.15

Monthly Capacity Price[1] ($/kW-month)

[1] Monthly Capacity Price expressed in whole dollars and cents B. Monthly Payment Price Shape Table [2] Month 2012 2013 2014 2015 2016 January 0% 20% 20% 96% 0% February 0% 10% 10% 48% 0% March 0% 10% 10% 48% 0% April 0% 10% 10% 48% 0% May 0% 30% 30% 144% 0% June 0% 45% 45% 216% 0% July 0% 330% 330% 0% 0% August 0% 405% 405% 0% 0% September 0% 240% 240% 0% 0% October 105% 35% 35% 0% 0% November 75% 25% 25% 0% 0% December 120% 40% 40% 0% 0% [2] Price shape is determined based on the heat rate of the Generating Unit, these values are contained in the All Source RFO Instructions. C. Maximum Monthly Capacity Payment ($) Month 2012 2013 2014 2015 2016 January $ - $ 46,620.00 $ 46,620.00 $ 223,776.00 $ - $ February $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ March $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ April $ - $ 23,310.00 $ 23,310.00 $ 111,888.00 $ - $ May $ - $ 69,930.00 $ 69,930.00 $ 335,664.00 $ - $ June $ - $ 104,895.00 $ 104,895.00 $ 503,496.00 $ - $ July $ - $ 769,230.00 $ 769,230.00 $ - $ - $ August $ - $ 944,055.00 $ 944,055.00 $ - $ - $ September $ - $ 559,440.00 $ 559,440.00 $ - $ - $ October $ 244,755.00 $ 81,585.00 $ 81,585.00 $ - $ - $ November $ 174,825.00 $ 58,275.00 $ 58,275.00 $ - $ - $ December $ 279,720.00 $ 93,240.00 $ 93,240.00 $ - $ - $

Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

56

2018 $ $ $ $ $ $ $ $ $ $ $ $

2017 -

2018 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2017 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

12.000

2019

2019 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

Enter Heat Rate at Pmax (MMBTU/MWh)

For the purposes of this template, figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year.

A. Monthly Capacity Price Information

Generating Unit Name: Sycamore Cogeneration Company Unit 4

-

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

$ $ $ $ $ $ $ $ $ $ $ $

2020

2020 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

2012 2013 2014 2015

Calendar Year

-

$ $ $ $ $ $ $ $ $ $ $ $

2021

2021 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

74.00

Contract Capacity (MW)

-

$ $ $ $ $ $ $ $ $ $ $ $

2022

2022 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

2023

2023 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

$ $ $ $ $ $ $ $ $ $ $ $

Base Price Shape 20% 10% 10% 10% 30% 45% 330% 405% 240% 35% 25% 40%

2024

2024 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0% 0%

-

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 3.1(b)

VARIABLE O&M CHARGE Generating Unit Name:

Sycamore Cogeneration Company Unit 2

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Generating Unit Name:

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

Sycamore Cogeneration Company Unit 4

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

57

Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 3.1(c)

START-UP CHARGE AND CAPACITY AND ANCILLARY SERVICES OPERATING RESTRICTIONS Generating Unit Name:

Sycamore Cogeneration Company Unit 2

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

0.00

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

58

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Generating Unit Name:

Sycamore Cogeneration Company Unit 4

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

0.00

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

59

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 5.3

HEAT RATE Generating Unit Name:

Sycamore Cogeneration Company Unit 2

A. Configuration 1 Information Minimum Generation Capacity (MW):

70.00

Maximum Generation Capacity (MW):

85.00

Heat Rate @ Pmax

12.000

Heat Rate @ Pmin

12.300

Increment (MW): B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.300

0.00

0.00

0.00

0.00

71.00

12.240

0.00

0.00

0.00

0.00

72.00

12.180

0.00

0.00

0.00

0.00

73.00

12.120

0.00

0.00

0.00

0.00

74.00

12.060

0.00

0.00

0.00

0.00

75.00

12.000

0.00

0.00

0.00

0.00

76.00

12.000

0.00

0.00

0.00

0.00

77.00

12.000

0.00

0.00

0.00

0.00

78.00

12.000

0.00

0.00

0.00

0.00

79.00

12.000

0.00

0.00

0.00

0.00

80.00

12.000

0.00

0.00

0.00

0.00

81.00

12.000

0.00

0.00

0.00

0.00

82.00

12.000

0.00

0.00

0.00

0.00

83.00

12.000

0.00

0.00

0.00

0.00

84.00

12.000

0.00

0.00

0.00

0.00

85.00

12.000

0.00

0.00

0.00

0.00

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Generating Unit Name:

Sycamore Cogeneration Company Unit 4

A. Configuration 1 Information Minimum Generation Capacity (MW):

Maximum Generation Capacity (MW):

70.00

Heat Rate @ Pmax

85.00

12.000

Heat Rate @ Pmin

12.300

Increment (MW):

B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.300

0.00

0.00

0.00

0.00

71.00

12.240

0.00

0.00

0.00

0.00

72.00

12.180

0.00

0.00

0.00

0.00

73.00

12.120

0.00

0.00

0.00

0.00

74.00

12.060

0.00

0.00

0.00

0.00

75.00

12.000

0.00

0.00

0.00

0.00

76.00

12.000

0.00

0.00

0.00

0.00

77.00

12.000

0.00

0.00

0.00

0.00

78.00

12.000

0.00

0.00

0.00

0.00

79.00

12.000

0.00

0.00

0.00

0.00

80.00

12.000

0.00

0.00

0.00

0.00

81.00

12.000

0.00

0.00

0.00

0.00

82.00

12.000

0.00

0.00

0.00

0.00

83.00

12.000

0.00

0.00

0.00

0.00

84.00

12.000

0.00

0.00

0.00

0.00

85.00

12.000

0.00

0.00

0.00

0.00

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APPENDIX 9.1 AVAILABILITY NOTICE

Operating Day: Station:

Issued By:

Generating Unit:

Issued At:

Generating Unit 100% Available No Restrictions:

Hour Ending

Minimum Output (MW) (non AGC)

Available Capacity

AGC Available

AGC Min Limit

AGC Max Limit

(MW)

YES/NO

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

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Comments

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.2(a) DISPATCH NOTICE

Operating Day: Station:

Issued By:

Generating Unit:

Hour Ending

Issued At:

Scheduled Energy

AGC Scheduled

Regulation Up

Regulation Down

Spinning Reserve

(MW)

YES/NO

(MW)

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

63

NonSpinning Reserves (MW)

Comments

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.2(b) START-UP NOTICE

Date: Station:

Issued By:

Generating Unit:

Issued At:

Date and Time Fire established in Applicable Generating Unit Date and Time Applicable Generating Unit Synchronized Date and Time Applicable Generating Unit Released for Dispatch Type of Start-Up (Hot, Warm, Cold) Fuel Consumed During Start-Up

(MMBtu)

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APPENDIX 9.2(d) DAILY OPERATING REPORT Daily Operating Reports submitted under this Confirmation should be provided in Excel. For: MM/DD/YY Plant Status at 0600

Generating Unit Name

Replicate for each Generating Unit

Current Availability (MW) Current Operating Level (MW) Current Restrictions (MW)

Prior Day Operating Level (HE)

Hourly Operating Level (Integrated)

Hourly Availability (Integrated)

Generating Unit on AS Control (Y/N)

Nature of Outage

Course of Action to Repair

Outage Date / Return Date

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00 Total Prior Day Significant Events:

Outages (Name of Equipment)

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 9.2(e) COMMUNICATION PROTOCOLS Communication Protocols These Communication Protocols are subject to change and shall be modified as evolving market conditions and rules may require. 1. Contacts and Authorized Representatives The “Contact Information” tables set forth those contact functions, phone/fax numbers and e-mail information by which each Party elects to be contacted by the other. Notification provided under this Confirmation shall be made to the applicable point of contact as set forth in the Contact Information Table. A Party may update its Contact Information by providing notice to the other Party. 2. Communication Protocols: General 2.1 Intra-day Communication: All communications and notices between the Parties that occur intra-day and intra-hour for the applicable Operating Day including those regarding emergencies, Dispatch Notices, Availability Notices, and notices to avoid imbalance penalties, uninstructed deviation charges/credits or any other CAISO charges shall be provided electronically or telephonically as SCE directs to the applicable Party. If to Seller, such notices and communications shall be provided to the following contact, in order of priority, (1) Dispatch Desk/Control Room, (2) Plant Manager, (3) Executive Director. If to SCE, such notices and communications shall be provided to the following contact, in order of priority, Real Time and Natural Gas Scheduling. Each Party shall confirm all Intra-day Communication either electronically or via telephone as soon as practicable. 2.2 Communication Failure: In the event of a failure of the primary communication link between Seller and SCE, both Parties will try all available means to communicate, including cell phones or additional communication devices as installed. 2.3 System Emergency: SCE and Seller shall communicate as soon as possible all changes to the schedule requested by the CAISO as a result of a system emergency. 2.4 Confidentiality: Confidential communications between the Parties in discharging their rights and obligations under the Confirmation and these Communication Protocols will be subject to the applicable restrictions set forth in the Confirmation. 2.5 Staffing: The Parties will have available twenty-four (24) hours a day, seven (7) days a week, personnel available to communicate regarding the implementation of these Communication Protocols.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Contact Information Table Contacts and Authorized Representatives for SCE Outlined below is the contact and communication information for the relevant contact groups. This list may be amended by SCE with timely notice to Seller. Primary Phone

Contact

Secondary Phone

Day-Ahead Trading

626-307-4487

Day-Ahead Scheduling

626-307-4425

Gas Trading Gas Scheduling

Fax

Email

626-302-3409

[email protected]

626-307-4420

626-302-3409

[email protected]

626-307-4480

626-302-4410*

626-302-3410

[email protected]

626-307-4479

626-302-4410*

626-302-3410

[email protected]

626-307-4410

Cell: 818-424-4575 Sat. Phone: 877-2482129 GOC Fly Away: 877220-9509 (only active in emergencies)

626-302-3409

[email protected] [email protected]

626-307-4410

Cell: 949-466-9909 Sat. Phone: 877-8065625

949-206-7840

[email protected] [email protected]

626-302-3277

626-302-3378

626-302-3276

[email protected]

Contract Administration

626-302-3216

[insert CM phone here]

626-302-8168

ESMpowercontractadmin@sce .com

Outage Scheduling / RA Substitution

626-302-3400

[email protected]

Availability Notices

626-302-3400

[email protected]

Real Time Notifications

Real Time – Backup Operations Center (not staffed, emergency only) Settlements – Power & Gas

*Contact the Real Time Generation Desk if after hours; RT will contact the on-call Gas Trader/Scheduler

Contacts and Authorized Representatives for Seller Outlined below is the contact and communication information for the relevant Seller employees. This list may be amended by Seller with timely notice to SCE. Desk

Contact

Direct Phone

Secondary Phones

Dispatch Desk (Day-Ahead) Dispatch Desk (Real Time) Outage Desk Plant Manager

67

Fax

Email

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Contract Administration Settlements Operations Manager Operations Supervisor

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the relevant provisions of PTC 22. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). Site Specific Reference Conditions (provided by Seller) Inlet Air (“Inlet Air”) Temperature (in °F)

38

Inlet Air Relative Humidity (in %)

25

Barometric Pressure (inches Hg)

28.5

For each Test set forth in this Appendix, the measured test data will be corrected to the Site Specific Reference Conditions using established correction factors. The corrected test data will then be compared to the Test Parameters. B. Parameters. During any Test, at a minimum, the following parameters will be measured and recorded simultaneously for the Generating Unit at no greater than fifteen (15) minute intervals (except for fuel samples): 1) 2) 3) 4) 5) 6) 7) 8)

instantaneous Inlet Air relative humidity (%) with instruments installed in the inlet filter house; instantaneous ambient barometric pressure (inches Hg) with transmitters located near the horizontal centerline of the Generating Unit; instantaneous Inlet Air temperature (°F) with four (4) remote telemetry devices installed in an array inside the filter house; instantaneous site ambient temperature (°F); fuel flow at the Generating Unit natural gas meter (SCFH); net plant output as measured at the Energy Delivery Point (MW); heat rate (BTU/kWh) @ PMax (for testing purposes only) continuous emissions monitoring system (CEMS) data required per air permit.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a qualified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters which will be defined in the Final Test Plan (Part III, A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time prior to commencing the four (4) hour test; operated for at least four (4) hours at an output, when corrected to Site Specific Reference conditions, is equal to PMax (“Full Load”); and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1. SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized and brought to Full Load using normal start procedures and then operated continuously at Full Load for as long as it is necessary, but in no case for no less than one (1) hour, for all measured parameters to achieve stable, normal conditions. During any 30minute period of any Test, all measured parameters will not exceed the values provided in Table 3-3.5 of PTC 22, “Maximum Permissible Standard Deviations of Measurements in Operating Conditions” in addition to the following: Variable Natural Gas Heating Value (Unit Volume) Absolute Inlet Air Pressure (inches H20)

Permissible Deviation ± 1.3% ± 0.33%

E. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in Part III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the equipment manufacturer for operation at PMax. F. Test Conditions. At all times during a Full Load Test, the Generating Unit shall be operated with any inlet cooling treatment systems on and such unit shall not be subject to abnormal operating conditions such as (i) ambient conditions requiring the inlet cooling system to be turned off in accordance with manufacturer’s specifications; (ii) unstable load conditions; (iii) equipment, operating or regulatory restrictions or (iv) changes in the Generating Unit’s electrical output other than those fluctuations naturally arising from variations in ambient temperature. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with Part II.J. below.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

G. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. H. Air Emissions. Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) Rule 2000 (c)(18) CEMS, is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. I. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Site Ambient Air Temperature Inlet Air Temperature Inlet Air Relative Humidity Barometric Pressure Measured Net Power Output Inlet Air Treatment (Evaporative Cooler, Foggers, or Chiller) Power Factor Steam / Water Injection Generating Unit Emissions Fuel Heating Value (HHV)

°F (Dry Bulb) °F (Dry Bulb) % inches Hg MW on/off

on/off (if applicable) Actual and permit levels BTU/Cubic ft

Note: If fuel analysis is not available by the fourth day after the Test is completed, Seller shall provide it on the earlier of when available or ten (10) Business Days after the Test is completed. J. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with Part II.I. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf,

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives, at Seller’s expense. K. Final Report. Within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 22. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8) (9)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3-5 of PTC 22; demonstration of the correction of the measured test data to the Site Specific Reference Conditions, with supporting calculations; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. L. Operating Personnel. During any Test, the same operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. M. SCE Representative. SCE shall be entitled to have at least two representatives present to witness each Test.

PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in Part II, above and in accordance with applicable Subsections of PTC 22, Section 3. At least ten (10) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and the temporary instrumentation suggested by Seller or deemed necessary by SCE in its sole judgement. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with written notice of the temporary calibrated instrumentation that will be used during the Test. Seller shall calibrate or cause to be calibrated all such instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE prior to the Test. Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. In addition Seller shall provide a temporary data acquisition system to monitor all temporary instruments. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling each Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1(a) of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test. G. Table. If SCE requests, Seller shall create a table relating Contract Capacity (in MW) to Inlet Air temperature, such that the Contract Capacity of the Generating Unit shall be the expected output of the Generating Unit at Test Conditions, and the expected output of the Generating Unit at other Inlet Air temperatures shall relate to Contract Capacity in the same proportion as the points on the manufacturer’s performance curve relate to that curve at Test Conditions. Such table will be provided to SCE as part of the Final Report.

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2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 11.1 PLANNED OUTAGE REPORT

Planned Outage Reports submitted under this Confirmation should be provided in Excel.

DATE OF UPDATE RESOURCE NAME Replicate for each Generating Unit

Planned Outages Start Date

HE

End Date

74

HE

MW Available

Cause

Emergency Time of Return

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 12.3 DELIVERY OF DATA The following is a list of real time generic data points to be electronically exchanged between Seller and SCE. SCE may add items to or delete items from this list at its reasonable discretion prior to the beginning of the Delivery Period. Additional meetings will be scheduled to clarify and finalize points list prior to configuration tasks.

Point description: From Generator DNP - XXX UNIT# Breaker DNP - XXX UNIT# AGC CTRL AVAILABILITY ONOFF DNP - XXX UNIT# ISO RIG Lost Communication DNP - XXX UNIT# High Operating Limit DNP - XXX UNIT# Low Operating Limit DNP - XXX UNIT# ISO AGC set point DNP - XXX UNIT# Net MW (POD) DNP - XXX UNIT# Capacity DNP - XXX UNIT# Max Sustained Ramp Rate

From GMS Control Related DNP - XXX UNIT# AGC model - ISO AGC DNP - XXX UNIT# AGC model – SFM DNP - XXX UNIT# AGC model – MAN DNP - XXX UNIT# AGC model – OFF DNP - XXX UNIT# Dispatch Energy Schedule "GO TO" DNP - XXX UNIT# Reg Up Awarded MW DNP - XXX UNIT# Reg Down Awarded MW DNP - XXX UNIT# Spin Awarded MW DNP - XXX UNIT# Non-Spin Awarded MW DNP - XXX UNIT# Set Point (MW) DNP - XXX UNIT# Ramp Rate (MW/M)

From GMS Schedules Related DNP - SCH HA Today XXX UNIT# HE01 DNP - SCH HA Today XXX UNIT# HE02 DNP - SCH HA Today XXX UNIT# HE03 DNP - SCH HA Today XXX UNIT# HE04 DNP - SCH HA Today XXX UNIT# HE05 DNP - SCH HA Today XXX UNIT# HE06 DNP - SCH HA Today XXX UNIT# HE07 DNP - SCH HA Today XXX UNIT# HE08 DNP - SCH HA Today XXX UNIT# HE09 DNP - SCH HA Today XXX UNIT# HE10 DNP - SCH HA Today XXX UNIT# HE11 DNP - SCH HA Today XXX UNIT# HE12 DNP - SCH HA Today XXX UNIT# HE13

75

From GMS Schedules Related (cont.) DNP - SCH HA Today XXX UNIT# HE14 DNP - SCH HA Today XXX UNIT# HE15 DNP - SCH HA Today XXX UNIT# HE16 DNP - SCH HA Today XXX UNIT# HE17 DNP - SCH HA Today XXX UNIT# HE18 DNP - SCH HA Today XXX UNIT# HE19 DNP - SCH HA Today XXX UNIT# HE20 DNP - SCH HA Today XXX UNIT# HE21 DNP - SCH HA Today XXX UNIT# HE22 DNP - SCH HA Today XXX UNIT# HE23 DNP - SCH HA Today XXX UNIT# HE24 DNP - SCH HA Today XXX UNIT# HE25 DNP - SCH HA Tomorrow XXX UNIT# HE01 DNP - SCH HA Tomorrow XXX UNIT# HE02 DNP - SCH HA Tomorrow XXX UNIT# HE03 DNP - SCH HA Tomorrow XXX UNIT# HE04 DNP - SCH HA Tomorrow XXX UNIT# HE05 DNP - SCH HA Tomorrow XXX UNIT# HE06 DNP - SCH HA Tomorrow XXX UNIT# HE07 DNP - SCH HA Tomorrow XXX UNIT# HE08 DNP - SCH HA Tomorrow XXX UNIT# HE09 DNP - SCH HA Tomorrow XXX UNIT# HE10 DNP - SCH HA Tomorrow XXX UNIT# HE11 DNP - SCH HA Tomorrow XXX UNIT# HE12 DNP - SCH HA Tomorrow XXX UNIT# HE13 DNP - SCH HA Tomorrow XXX UNIT# HE14 DNP - SCH HA Tomorrow XXX UNIT# HE15 DNP - SCH HA Tomorrow XXX UNIT# HE16 DNP - SCH HA Tomorrow XXX UNIT# HE17 DNP - SCH HA Tomorrow XXX UNIT# HE18 DNP - SCH HA Tomorrow XXX UNIT# HE19 DNP - SCH HA Tomorrow XXX UNIT# HE20 DNP - SCH HA Tomorrow XXX UNIT# HE21 DNP - SCH HA Tomorrow XXX UNIT# HE22 DNP - SCH HA Tomorrow XXX UNIT# HE23 DNP - SCH HA Tomorrow XXX UNIT# HE24 DNP - SCH HA Tomorrow XXX UNIT# HE25

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 13.3(c) DISCLOSURE SCHEDULE None

76

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 13.3(d) HISTORICAL OUTAGE REPORT SYCAMORE COGENERATION COMPANY GENERATING UNIT # 2 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2

Available Time Thu 01Jan09 00:00 Mon 12Jan09 11:14 Tue 13Jan09 12:00 Wed 14Jan09 16:07 Thu 15Jan09 12:18 Mon 23Feb09 09:06 Tue 10Mar09 07:50 Thu 23Apr09 08:54 Fri 08May09 02:04 Sun 17May09 15:44 Sun 17May09 17:02 Thu 04Jun09 03:41 Tue 09Jun09 11:42 Fri 18Sep09 07:30 Fri 18Sep09 10:09 Tue 22Sep09 01:45 Thu 24Sep09 11:21 Tue 29Sep09 12:00 Fri 06Nov09 12:00 Tue 09Feb10 20:12 Sat 20Feb10 17:24 Wed 24Feb10 14:30 Mon 22Mar10 16:49 Tue 23Mar10 06:43 Tue 29Jun10 00:36 Mon 05Jul10 13:42 Fri 09Jul10 00:51 Tue 20Jul10 09:48 Wed 04Aug10 09:13 Fri 27Aug10 10:44 Tue 04Jan11 09:29 Sun 09Jan11 12:10 Sun 09Jan11 18:31 Thu 09Jun11 09:46 Tue 21Jun11 12:11 Fri 24Jun11 13:58 Mon 27Jun11 12:23 Sat 03Dec11 10:02 Wed 07Dec11 08:28 Thu 08Dec11 07:50 Fri 13Jan12 07:32 Fri 27Jan12 04:47 Fri 27Jan12 12:41 Mon 06Feb12 10:34 Fri 17Feb12 07:50 Fri 24Feb12 08:45 Wed 07Mar12 08:11 Wed 07Mar12 09:08

UnAvailable Time Fri 09Jan09 10:55 Mon 12Jan09 11:46 Tue 13Jan09 13:44 Wed 14Jan09 17:06 Mon 23Feb09 06:06 Tue 10Mar09 07:08 Tue 21Apr09 10:19 Fri 08May09 01:33 Sun 17May09 14:30 Sun 17May09 16:34 Thu 04Jun09 03:10 Tue 09Jun09 11:12 Mon 14Sep09 00:01 Fri 18Sep09 08:22 Tue 22Sep09 01:12 Wed 23Sep09 12:12 Mon 28Sep09 00:05 Mon 02Nov09 07:00 Tue 09Feb10 19:43 Sat 20Feb10 16:48 Wed 24Feb10 13:58 Mon 22Mar10 16:18 Tue 23Mar10 05:42 Tue 29Jun10 00:06 Mon 05Jul10 12:52 Fri 09Jul10 00:31 Tue 20Jul10 09:32 Tue 03Aug10 07:00 Fri 27Aug10 10:13 Tue 04Jan11 05:42 Sun 09Jan11 07:02 Sun 09Jan11 15:54 Thu 09Jun11 08:04 Tue 21Jun11 11:42 Fri 24Jun11 12:00 Mon 27Jun11 12:04 Sat 03Dec11 08:10 Tue 06Dec11 22:02 Wed 07Dec11 20:35 Fri 13Jan12 07:00 Fri 27Jan12 04:04 Fri 27Jan12 12:29 Mon 06Feb12 10:24 Thu 16Feb12 17:34 Fri 24Feb12 07:25 Wed 07Mar12 01:57 Wed 07Mar12 08:49 Tue 01May12 00:00 Total Available Hours TotalHours % Available

Available Hours 202.9 0.5 1.7 1.0 929.8 358.0 1010.5 352.6 228.4 0.8 418.1 127.5 2316.3 0.9 87.0 34.5 84.7 811.0 2287.7 260.6 92.6 625.8 12.9 2345.4 156.3 82.8 272.7 333.2 553.0 3115.0 117.6 3.7 3613.5 289.9 71.8 70.1 3811.8 84.0 12.1 863.2 332.5 7.7 237.7 247.0 167.6 281.2 0.6 1310.9 28,627.3 29,184.0 98.1%

Unavailable Hours 72.3 24.2 26.4 19.2 3.0 0.7 46.6 0.5 1.2 0.5 0.5 0.5 103.5 1.8 0.5 23.2 35.9 101.0 0.5 0.6 0.5 0.5 1.0 0.5 0.8 0.3 0.3 26.2 0.5 3.8 5.1 2.6 1.7 0.5 2.0 0.3 1.9 10.4 11.3 0.5 0.7 0.2 0.2 14.3 1.3 6.2 0.3 0.0 556.7

77

Reason UnAvailable Shutdown due to Emissions Exceedence Emissions Exceedence - CLEC Maintenance Emissions Exceedence - Rebooted RSTC Computers Emissions Exceedence Troubleshooting Crankwash Emissions Exceedence - Reset and Restarted NERC Required Transformer Inspection - Crankwash Combustion Dynamics Erratic - Reset and Restarted CLEC System Trouble - Reset and Restarted Unit CLEC System Trouble - Reset and Restarted Unit Unit Tripped - Failure to Reignite Primaries Emissions Exceedence - Restarted Combustion Inspection Combustion Inspection- Testing Emissions Exceedence - Restarted Secondary Fuel Nozzle Mainenancee Inspect Primary Fuel Nozzles for leakage Mini Combustion Inspection Unit Shutdown due to Flashbacks - Restarted Emissions Exceedence - Reset and Restarted Unit Shutdown due to Flashbacks - Restarted Unit Shutdown due to Flashbacks - Restarted Emissions Exceedence - Replaced by Unit 4 Manual shutdown due to Flashbacks - Reset and Restarted Unit Manual shutdown due to Flashbacks Manual shutdown due to Flashbacks Manual shutdown due to Flashbacks Replaced Secondary Fuel Nozzles Flashback and Trip During OnLine Wash - Reset and Restarted High CO Emissions High CO Emissions High CO Emissions Cleaned dirty flame detectors Over excitation trip due to voltage swing during voltage adjustment - restarted Over excitation trip due to voltage swing during voltage adjustment - restarted Over excitation trip due to voltage swing during voltage adjustment - restarted Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Flashbacks - Emissions Exceedence Flashbacks - Emissions Exceedence Investigate Unstable Flame in Secondary Burners - Extra Unit Emissions Exceedence required shutdown Emissions Exceedence required shutdown End of File

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

SYCAMORE COGENERATION COMPANY GENERATING UNIT # 4 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4

Available Time Thu 01Jan09 00:00 Mon 09Mar09 03:22 Tue 21Apr09 09:49 Wed 02Sep09 14:18 Sat 03Oct09 18:55 Mon 16Nov09 11:43 Thu 07Jan10 01:04 Sat 09Jan10 09:59 Sat 09Jan10 12:43 Sun 10Jan10 07:54 Sun 10Jan10 11:05 Mon 11Jan10 04:32 Sun 18Apr10 23:48 Sat 22May10 15:43 Sat 08Jan11 14:35 Mon 21Feb11 21:41 Tue 01Nov11 00:00 Fri 09Dec11 01:47 Wed 11Jan12 07:19 Wed 11Jan12 09:59 Thu 12Jan12 06:25 Thu 16Feb12 09:18 Fri 17Feb12 07:50 Fri 17Feb12 19:32 Sat 25Feb12 14:32 Fri 02Mar12 23:33 Tue 06Mar12 20:34 Wed 07Mar12 09:08 Fri 06Apr12 06:20

UnAvailable Time Mon 09Mar09 02:48 Thu 09Apr09 11:01 Wed 02Sep09 13:45 Sat 03Oct09 02:12 Mon 16Nov09 10:13 Thu 07Jan10 00:56 Sat 09Jan10 03:09 Sat 09Jan10 11:25 Sun 10Jan10 07:20 Sun 10Jan10 10:33 Mon 11Jan10 03:21 Sun 18Apr10 21:37 Sat 22May10 13:39 Sun 02Jan11 10:27 Mon 21Feb11 21:06 Mon 24Oct11 07:00 Fri 09Dec11 01:36 Wed 11Jan12 03:52 Wed 11Jan12 09:26 Thu 12Jan12 05:53 Mon 13Feb12 07:00 Thu 16Feb12 15:32 Fri 17Feb12 18:55 Sat 25Feb12 13:58 Fri 02Mar12 23:02 Tue 06Mar12 19:59 Tue 06Mar12 23:02 Fri 06Apr12 05:31 Tue 01May12 00:00 Total Available Hours TotalHours % Available

Available Hours 1610.8 751.6 3219.9 731.9 1047.3 1237.2 50.1 1.4 18.6 2.6 16.3 2345.1 805.8 5394.7 1062.5 5865.3 913.6 794.1 2.1 19.9 768.6 6.2 11.1 186.4 152.5 92.4 2.5 716.4 593.7 28,420.8 29,184.0 97.4%

Unavailable Hours 0.6 286.8 0.6 16.7 1.5 0.1 6.8 1.3 0.6 0.5 1.2 2.2 2.1 148.1 0.6 185.0 0.2 3.4 0.6 0.5 74.3 16.3 0.6 0.6 0.5 0.6 10.1 0.8 0.0 763.2

78

Reason UnAvailable Emissions Exceedence - CLEC valve maintenance CEMS Multi-Port System Installed - NERC Inspection - CW Reset C Computer Following Computer Trip DCS/Ovation Upgrade Unit Accidentally Tripped during Switchyard relay maintenance Shutdown to Troubleshoot Flash Back Cause Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Tripped on Loss Of Flame - Cleaned Flame Detectors Replaced Failed Flame Detectors #7 & #8 Combustion Inspection High Nox Emissions Exhaust Duct Maintenance Emissions Exceedence required shutdown Flashback - Failed to re-ignite primaries Emissions Exceedence required shutdown Emissions Exceedence required shutdown Mini Combustion Inspection - Fuel Nozzles replaced Replaced #9 Secondary Fuel Nozzle Emissions Exceedence required shutdown High Combustion Dynamics Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown End of File

2012 CHP Energy Only UC Toll (Kern Pipeline--financially settled gas)

APPENDIX 14 SHAPED PRICE CALCULATION 1

Shape Calculation a) “Shape” shall be the ratio, expressed as a percentage, of a Forward Price Assessment of (i) the price of power for a calendar quarter to the price of power for the calendar year that such quarter falls within, or (ii) the price of power for a month to the price of power for the quarter that such month falls within. b) There are four quarterly Shapes (for the first through fourth calendar quarters) and twelve monthly Shapes (for the months of January through December) in every calendar year. 1.

For purposes of determining the applicable quarterly Shape, an annual price is calculated as the simple average of the four quarterly prices within the last available year. For example, the first quarter Shape is calculated using the formula below: ShapeQ1 = PQ1 / Average (PQ1 + PQ2 + PQ3 + PQ4)

2.

For purposes of determining the applicable monthly Shape, a quarterly price is calculated as the simple average of the three monthly prices within the applicable quarter. For example, the January Shape is calculated using the formula below: ShapeJan = PJan / Average (PJan + PFeb + PMar)

2

Calculation of Shaped Prices “Shaped Price” shall mean, if there is no Forward Price Assessment for the relevant calendar month, the price of power calculated in accordance with the following process. If no monthly price is available for a Forward Price Assessment but a quarterly price is available, then use a monthly Shape to calculate a monthly Shaped Price from a quarterly price using the following formula: PM = PQ × ShapeM Where: PM is the missing monthly power price PQ is the quarterly power price applicable to the relevant calendar month ShapeM is the applicable “Shape” for the missing month If no monthly or quarterly price is available for a Forward Price Assessment but an annual price is available, then use a quarterly Shape to calculate a quarterly Shaped Price from an annual price using the following formula: PQ = PY × ShapeQ Where: PQ is the missing quarterly power price PY is the yearly power price applicable to the applicable calendar quarter ShapeQ is the applicable “Shape” for the missing quarter

79

PARAGRAPH 10 to the COLLATERAL ANNEX to the EEI MASTER POWER PURCHASE AND SALE AGREEMENT Between Sycamore Cogeneration Company (“Party A”) and Southern California Edison Company (“SCE” or “Party B”) CREDIT ELECTIONS COVER SHEET Paragraph 10. Elections and Variables I.

Collateral Threshold. A.

Party A Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party A shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party A; and provided further that, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party A Collateral Threshold” opposite the Credit Rating for [Party A][Party A’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party A][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing; provided, however, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand. Party A Collateral Threshold $__________ $__________ $__________ $__________ $__________



Credit Rating _______ (or above) _______ _______ _______ Below _______

The amount (“Threshold Amount”) which is the lowest of:

(1) the amount set forth below under the heading “Party A Collateral Threshold” opposite the lower of the Credit Ratings for Party A or, if applicable, Party A’s Guarantor on the relevant date of determination. If Party A or, if applicable, its Guarantor is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party A or, if applicable, its Guarantor is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party A or, if applicable,

1

its Guarantor does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) 80% of the amount of the guaranty agreement, as amended from time to time, provided by Party A’s Guarantor, if any, for the benefit of Party B; or (3) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing: Party A Collateral Threshold (in thousands of US Dollars) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero)

B.

Moody’s Credit Rating

S&P Credit Rating

Fitch Credit Rating

Aa3 or above A1 A2 A3 Baa1 Baa2 Baa3 Ba1 or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party A’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Party B Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party B shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party B; and provided further that, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party B Collateral Threshold” opposite the Credit Rating for [Party B][Party B’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party B][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing; provided, however, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand:

2



Party B Collateral Threshold

_____Credit Rating

$__________ $__________ $__________ $__________ $__________

_______ (or above) _______ _______ _______ Below _______

The amount (the “Threshold Amount”) which is the lower of:

(1) the amount set forth below under the heading “Party B Collateral Threshold” opposite the lower of the Credit Ratings for Party B on the relevant date of determination. If Party B is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party B is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party B does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing: Party B Collateral Threshold (in thousands of US Dollars) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero) $ 0 (zero)

II.

Moody’s Credit Rating

S&P Credit Rating

Fitch Credit Rating

Aa3 or above A1 A2 A3 Baa1 Baa2 Baa3 Ba1 or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below

AA- or above A+ A ABBB+ BBB BBBBB+ or below



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party B’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Eligible Collateral and Valuation Percentage. The following items will qualify as "Eligible Collateral" for the Party specified: Party A

Party B

Valuation Percentage

(A)

Cash

[X]

[X]

100%

(B)

Letters of Credit

[X]

[X]

100% unless either (i) a Letter of Credit Default shall have occurred and be continuing with respect to such Letter of Credit, or (ii) twenty (20) or fewer Business Days remain prior to the expiration of such Letter of Credit, in which cases the Valuation Percentage shall be zero (0%).

(C)

Other

[ ]

[ ]

3

________%

III.

Independent Amount. A.

B.

Party A Independent Amount. 

Party A shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount option is selected for Party A, then Party A (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party B (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party A’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex.



Party A shall have a Full Floating Independent Amount of (i) the amount specified in a Transaction or Confirmation, if any; and (ii) if Party A’s Credit Rating is lower than BBBby S&P, Baa3 by Moody’s, or BBB- by Fitch, the amount equal to ten percent (10%) of the market value of all outstanding Transactions (except those for which an alternative Independent Amount is specified in the Confirmation), adjusted by the netting of the market value of purchases with the market value of sales within the same billing cycles. If the Full Floating Independent Amount option is selected for Party A, then for purposes of calculating the Collateral Requirements pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party A shall be added to the Exposure Amount for Party B and subtracted from the Exposure Amount for Party A.



Party A shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party A, then Party A will be required to Transfer or cause to be Transferred to Party B Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party A otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced so long as Party A has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex.



Not Applicable.

Party B Independent Amount. 

Party B shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount Option is selected for Party B, then Party B (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party A (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party B’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex.

4

IV.

V.

VI.



Party B shall have a Full Floating Independent Amount of $______________. If the Full Floating Independent Amount Option is selected for Party B then for purposes of calculating Party B’s Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party B shall be added by Party A to its Exposure Amount for purposes of determining Net Exposure pursuant to Paragraph 3(a) of the Transition Collateral Annex.



Party B shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party B, then Party B will be required to Transfer or cause to be Transferred to Party A Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party B otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced for so long as Party B has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex.



Not Applicable.

Minimum Transfer Amount. A.

Party A Minimum Transfer Amount:

$0.00

B.

Party B Minimum Transfer Amount:

$0.00

Rounding Amount. A.

Party A Rounding Amount:

$250,000.00

B.

Party B Rounding Amount:

$250,000.00

Administration of Cash Collateral. A.

Party A Eligibility to Hold Cash. 

Party A shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B.



Party A shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party A or, if applicable, Party A’s Guarantor has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party A or its Guarantor has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or on “Credit Watch” negative or developing by

5

Fitch, then Party A shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party A is entitled to hold Cash, the Interest Rate payable to Party B on Cash shall be as selected below:

Party A Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

To the extent that Party A is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B. B.

Party B Eligibility to Hold Cash. 

Party B shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A.



Party B shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party B has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party B has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or “Credit Watch” negative or developing by Fitch, then Party B shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party B is entitled to hold Cash, the Interest Rate payable to Party A on Cash shall be as selected below: Party B Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

To the extent that Party B is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it

6

receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A. VII.

Notification Time. 10:00 a.m. Pacific Prevailing Time on a Local Business Day.

VIII.

General. With respect to the Collateral Threshold, Independent Amount, Minimum Transfer Amount and Rounding Amount, if no selection is made in this Cover Sheet with respect to a Party, then the applicable amount in each case for such Party shall be zero (0). In addition, with respect to the “Administration of Cash Collateral” section of this Paragraph 10, if no selection is made with respect to a Party, then such Party shall not be entitled to hold Performance Assurance in the form of Cash and such Cash, if any, shall be held in a Qualified Institution pursuant to Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. If a Party is eligible to hold Cash pursuant to a selection in this Paragraph 10 but no Interest Rate is selected, then the Interest Rate for such Party shall be the Federal Funds Effective Rate as defined in Section VI of this Paragraph 10.

IX.

Other Changes. The following changes to the Collateral Annex shall be applicable. A.

Introduction. The first paragraph of the introduction is amended to read as follows: “This Collateral Annex, together with the Paragraph 10 Cover Sheet, (the “Transition Collateral Annex”) supplements, forms a part of, and is subject to the EEI Master Power Purchase and Sale Agreement dated as of October 15, 2012 between Sycamore Cogeneration Company (“Party A”) and Southern California Edison Company (“Party B”), including the Cover Sheet and any other annexes thereto (as amended and supplemented from time to time, the “Agreement”). Capitalized terms used in this Transition Collateral Annex but not defined herein shall have the meanings given such terms in the Agreement.”

B.

Paragraph 1. Definitions. Amend Paragraph 1 as follows: i. The definition of “Credit Rating” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.12 of the Transition Master Agreement as modified in the Cover Sheet. ii. The definition of “Credit Rating Event” is amended by replacing “6(a)(iii)” with “6(a)(ii)”. iii. The definition of “Downgraded Party” is amended by replacing “6(a)(i)” with “6(a)(ii)”. iv. The definition of “Letter of Credit” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.27 of the Transition Master Agreement as modified in the Cover Sheet. v. The definition of “Letter of Credit Default” is amended by replacing the word “or” in the third line with the word “and”. vi. The definition of “Local Business Day” is amended by replacing the word “day” with “Business Day”. vii. The definition of “Notification Time” is amended by replacing “11:00, New York” with “10:00 a.m. Pacific Prevailing.” viii. The definition of “Performance Assurance” is amended by replacing “6(a)(iv)” with “6(a)(iii)”. ix. The definition of “Qualified Institution” is amended as follows:

7

“ “Qualified Institution” means a commercial bank or trust company organized under the laws of the United States or a political subdivision thereof, with (i) a Credit Rating of at least (a) "A-" by S&P, "A3" by Moody's, and “A-” by Fitch, if such entity is rated by all three Ratings Agencies; or (b) "A-" by S&P, "A3" by Moody's, or “A-” by Fitch, if such entity is rated by only two Ratings Agencies, and (ii) having a capital surplus of at least ONE BILLION AND 00/100 DOLLARS ($1,000,000,000.00).” x. The definition of “Reference Market-maker” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.71 of the Transition Master Agreement as modified in the Cover Sheet. xi. The definition of “Secured Party” is amended by replacing “3(b)” with “3(a)”. C.

Paragraph 3. Calculations of Collateral Requirement. In Paragraph 3(b)(2), is amended by replacing the comma after “Secured Party” with “and” and by deleting the phrase “, and any Interest Amount that has not yet been Transferred to the Pledging Party”.

D.

Paragraph 4. Delivery of Performance Assurance. In Paragraph 4, the penultimate sentence is amended by replacing the words “next Local Business Day” with “third Local Business Day thereafter” in clause (i), and by replacing the word “second” with fourth” in clause (ii).

E.

Paragraph 5. Reduction and Substitution of Performance Assurance. Amend Paragraph 5 as follows: i. Paragraph 5(a) is amended by deleting the parenthetical “(but no more frequently than weekly with respect to Letters of Credit and daily with respect to Cash)” from the first line. ii. The sixth sentence of Paragraph 5(a) is amended by inserting the word “Local” before “Business Day,” in clause (i) of that sentence.

F.

Paragraph 6. Administration of Performance Assurance. Amend Paragraph 6 as follows: i. Paragraph 6(a)(ii)(A) is amended by inserting “(other than subparagraph (B) below)” after “the provisions of this Paragraph 6(a)(ii)” in the first line thereof. ii. Paragraph 6(a)(ii)(B) is amended by replacing “Non-Downgraded Party” with “Downgraded Party”. iii. Paragraph 6(b)(iv) is amended by capitalizing the second instance of the word “cash” in the second sentence. iv. Paragraph 6(b)(v) is amended by replacing the parenthetical phrase “(including but not limited to the reasonable costs, expenses, and attorneys’ fees of the Secured Party)” with “(excluding attorneys’ fees)”.

G.

Paragraph 7. Exercise of Rights Against Performance Assurance. Paragraph 7(b) is amended by deleting it in its entirety and inserting the words “Intentionally Omitted.”.

H.

Paragraph 8. Disputed Calculations. Amend Paragraph 8 as follows: i. Paragraph 8(a) is amended by adding in the third sentence the phrase “and, provided further, that if no quotations can be obtained, then the Secured Party’s original calculation shall be used” immediately after the words “then that quotation shall be used” and before the “)”. ii. Paragraph 8(b) is amended by (1) adding the words “requested by the Pledging Party” between the word “Assurance” and the phrase “to be reduced”, and (2) adding in the third sentence the phrase “and, provided further that, if no quotations can be obtained, then the Secured Party’s

8

2012 CHP RA Capacity

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN SYCAMORE COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY This confirmation letter (“Confirmation”) confirms the Transaction between Sycamore Cogeneration Company (“Seller” or “Sycamore”) and Southern California Edison Company (“Buyer” or “SCE”), each individually a “Party” and together the “Parties”, dated as of October 15, 2012, (the “Confirmation Effective Date”) in which Seller agrees to provide to Buyer the right to the Product. This Transaction is governed by the Edison Electric Institute Master Power Purchase and Sale Agreement between the Parties, effective as of October 15, 2012, along with the Cover Sheet (the “Transition Cover Sheet:”), any amendments and annexes thereto (the “Transition Master Agreement”), and including Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement”. Capitalized terms used but not otherwise defined in this Confirmation have the meanings ascribed to them in the Transition EEI Agreement, or the Tariff (defined herein below). RECITALS A.

Seller owns and operates Generating Unit # 2 and Generating Unit # 4, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement;

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement; and

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition Tolling Confirmation and the Transition PPA.

ARTICLE 1 DEFINITIONS “Applicable Laws” means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Body having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. “Availability Incentive Payments” has the meaning set forth in the Tariff. “Availability Standards” has the meaning set forth in the Tariff. “Buyer" has the meaning specified in the introductory paragraph hereof. “CAISO” means the California Independent System Operator or any successor entity performing the same functions. “Capacity Attributes” means, with respect to a Generating Unit, any and all of the following, in each case which are attributed to or associated with the Generating Unit at any time throughout the Delivery Period: (a)

resource adequacy attributes, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward RAR;

(b)

resource adequacy attributes or other locational attributes for the Generating Unit related to a Local Capacity Area, as may be identified from time to time by the CPUC, CAISO or other Governmental Body having jurisdiction, associated with the physical location or

1

2012 CHP RA Capacity

point of electrical interconnection of the Generating Unit within the CAISO Control Area, that can be counted toward a Local RAR; (c)

flexible capacity resource adequacy attributes for the Generating Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward Flexible RAR; and

(d)

other current or future defined characteristics, certificates, tags, credits, or accounting constructs, howsoever entitled, including any accounting construct counted toward any RAR, Local RAR or Flexible RAR.

“Capacity Flat Price” means the price specified in the Capacity Flat Price Table in Section 4.1. “Capacity Replacement Price” means the market price for the quantity of Product not provided by Seller under this Confirmation as determined in the manner upon which market prices are determined under Section 5.2(b) of the Transition Master Agreement. For purposes of Section 1.51 of the Transition Master Agreement, “Capacity Replacement Price” shall be deemed the “Replacement Price” for this Transaction. “CHP” has the meaning set forth in Section 8.3. “Confirmation” has the meaning specified in the introductory paragraph hereof. “Confirmation Effective Date” has the meaning specified in the introductory paragraph hereof. “Contingent Firm RA Product" has the meaning specified in Section 2.3 hereof. “Contract Price” means, for any Showing Month, the Capacity Flat Price. “Contract Quantity” has the meaning set forth in Section 2.5 and means the total Unit Quantity for all Generating Units. “CPUC Approval” means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of this Confirmation, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. “CPUC Decisions” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 06-04-040, 06-06-064, 0607-031, 07-06-029, 08-06-031, 09-06-028, 10-06-036, 11-06-022, 12-06-025, and any other existing or subsequent decisions, resolutions, or rulings related to resource adequacy, including, without limitation, the CPUC Filing Guide, in each case as may be amended from time to time by the CPUC. “CPUC Filing Guide” is the annual document issued by the CPUC which sets forth the guidelines, requirements and instructions for LSE’s to demonstrate compliance with the CPUC’s RA program. “Delivery Period” has the meaning specified in Section 2.4. “Delivery Period End Date” has the meaning specified in Section 2.4. “FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at marketbased rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal.

2

2012 CHP RA Capacity

“Firm RA Product" has the meaning specified in the Section 2.2 hereof. “Flexible RAR” means the flexible capacity requirements, including, without limitation, maximum continuous ramping, load following, and regulation, established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Flexible RAR may also be known as ramping, maximum ramping, maximum continuous ramping, maximum continuous ramping capacity, maximum continuous ramping ramp rate, load following, load following capacity, load following ramp rate, regulation, regulation capacity, and/or regulation ramp rate. “Flexible RAR Showings” means the Flexible RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. “GADS” means the Generating Availability Data System, or its successor. “Generating Facility” means the power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. For purposes of this Confirmation, the Generating Facility shall include Generating Unit # 2 and Generating Unit # 4 for the Delivery Period set forth in Section 2.4. “Generating Unit” or “Generating Units” shall mean the generation assets described in Appendix A (including any Replacement Units), from which Product is provided by Seller to Buyer. Unless otherwise stated in this Confirmation, references to Generating Unit or Generating Units shall be applicable only to Generating Until # 2 and Generating Unit #4 throughout the Delivery Period. “Generating Unit # 2” means the Generating Unit described in Appendix A(a). “Generating Unit # 4” means the Generating Unit described in Appendix A(c). “Governmental Body” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal. “Local Capacity Area” has the meaning set forth in the Tariff. “Local RAR” means the local resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Local RAR may also be known as local area reliability, local resource adequacy, local resource adequacy procurement requirements, or local capacity requirement in other regulatory proceedings or legislative actions. “Local RAR Showings” means the Local RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. “LSE” means load-serving entity. “Monthly Delivery Period” means each calendar month during the Delivery Period and shall correspond to each Showing Month. “Monthly Payment” has the meaning specified in Section 4.1. “NERC” means the North American Electric Reliability Corporation, or its successor. “NERC/GADS Protocols” means the GADS protocols established by NERC, as may be updated from time to time. “Net Qualifying Capacity” has the meaning set forth in the Tariff. “Non-Availability Charges” has the meaning set forth in the Tariff.

3

2012 CHP RA Capacity

“Outage” means any disconnection, separation or reduction in the capacity of any Generating Unit, other than a Planned Outage but including, without limitation, any such disconnection, separation or reduction in capacity that is designated as either forced or unplanned pursuant to the Tariff or the NERC/GADS Protocols. “Outage Schedule” has the meaning specified in Section 7.1. “Planned Outage” means an Approved Maintenance Outage (as defined in the Tariff), but does not include a RA Maintenance Outage with Replacement (as defined in the Tariff), a Short-Notice Opportunity RA Maintenance Outage (as defined in the Tariff) or an Off-Peak Opportunity RA Maintenance Outage (as defined in the Tariff). “Power Rating” means the electrical power output value indicated on the generating equipment nameplate. “Product” means the Capacity Attributes of the Generating Unit, provided that: (a)

Product does not include any right to the energy or ancillary services from the Generating Units;

(b)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Local Capacity Areas that results in a decrease or increase in the amount of Capacity Attributes related to a Local Capacity Area provided hereunder will not result in a change in payments made pursuant to this Transaction;

(c)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Flexible RAR, Capacity Attributes related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR, that results in a decrease or increase in the amount of Capacity Attributes related to Flexible RAR provided hereunder will not result in a change in payments made pursuant to this Transaction;

(d)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Local Capacity Areas whereby the a Generating Unit subsequently qualifies for a Local Capacity Area, the Product shall include all Capacity Attributes related to such Local Capacity Area; and

(e)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Flexible RAR, Capacity Attributes related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR whereby the a Generating Unit subsequently qualifies for to satisfy Flexible RAR, the Product shall include all Capacity Attributes related to Flexible RAR.

“PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. “Qualifying Facility” means an electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of self-certification pursuant to 18 CFR Part 292.207(a). “RAR” means the resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. “RAR Showings” means the RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. “Replacement Capacity” has the meaning specified in Section 5.2. “Replacement Unit” means a generating unit meeting the requirements specified in Section 5.1.

4

2012 CHP RA Capacity

“Resource Category” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “Resource ID” has the meaning set forth in the Tariff. “RFO Agreement” means the Master Power Purchase and Sale Confirmation Letter (RA Capacity) between the Parties, dated July 2, 2012, as may be amended from time to time. “Scheduling Coordinator” or “SC” has the meaning set forth in the Tariff. “Settlement Agreement” means the Qualifying Facility and Combined Heat and Power Program Settlement Agreement, approved by the CPUC in Decision 10-12-035 issued on December 21, 2010, effective November 23, 2011. “Seller” has the meaning specified in the introductory paragraph hereof. “Shortfall Capacity” has the meaning set forth in Section 3.4. “Showing Month” shall be the calendar month of the Delivery Period that is the subject of the RAR Showing, Local RAR Showing or Flexible RAR Showing, in each case, as set forth in the CPUC Decisions and outlined in the Tariff. For illustrative purposes only, pursuant to the Tariff and CPUC Decisions in effect as of the Confirmation Effective Date, the monthly RAR Showing made in June is for the Showing Month of August. “Substitute Capacity” has the meaning set forth in Section 10.1. “Substitution Rules” has the meaning set forth in Section 10.2. “Supply Plan” has the meaning set forth in the Tariff. “Tariff” means the tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. “Term” shall have the following meaning: The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied. “Transition Agreement” has the meaning specified in the introductory paragraph hereof. “Transition Collateral Annex” has the meaning specified in the introductory paragraph hereof. “Transition Cover Sheet” has the meaning specified in the introductory paragraph hereof. “Transition Master Agreement” has the meaning specified in the introductory paragraph hereof. “Transition PPA” has the meaning set forth in the Transition Cover Sheet. “Transition Tolling Confirmation” means that certain Tolling Confirmation of even date herewith between Seller and Buyer, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. “Unit NQC” means the Net Qualifying Capacity set by the CAISO for the applicable Generating Unit. The Parties agree that if the CAISO adjusts the Net Qualifying Capacity of a Generating Unit after the Confirmation Effective Date, that for the period in which the adjustment is effective, the Unit NQC shall be deemed the lesser of (i) the Unit NQC as of the Confirmation Effective Date, or (ii) the CAISO-adjusted Net Qualifying Capacity. “Unit Quantity” means the amount of Product (in MWs) provided by Seller to Buyer by each individual Generating Unit identified in Section 2.5 during the portions of the Delivery Period the Generating Unit is subject to the obligations of this Confirmation and subject to reductions as outlined in Section 3.2.

5

2012 CHP RA Capacity

ARTICLE 2 TRANSACTION 2.1 2.2

[Intentionally omitted] Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity for each day of each month of the Delivery Period If the Generating Units are not available to provide the full amount of the Contract Quantity for each day of a Showing Month for any reason, including without limitation any Outage or Planned Outage or any adjustment of the Capacity Attributes of any Generating Unit, Seller shall provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1 hereof. If Seller fails to provide Buyer with Replacement Capacity from Replacement Units pursuant to Section 5.1, then Seller shall be liable for damages and/or to indemnify Buyer for penalties or fines pursuant to the terms of Article Five. The Parties agree that Section 3.2 shall not apply if this Section 2.2 has been elected. 2.3

Contingent Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity for each day of each month of the Delivery Period. If the Generating Units are not available to provide the full amount of the Contract Quantity for each day of a Showing Month, Seller may elect to provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1. In such case, if Seller elects to provide Replacement Capacity pursuant to Section 5.1 and fails or if Seller elects not to provide such Replacement Capacity, then Seller shall be liable for damages and/or shall indemnify Buyer for penalties or fines pursuant to the terms of Article Five. If the Generating Units provide less than the full amount of the Contract Quantity in the event of a Planned Outage or a reduction to Unit NQC, Seller is not obligated to provide Buyer with Replacement Capacity and shall not be liable for damages or obligated to indemnify Buyer for penalties or fines pursuant to Article 5 hereof. Notwithstanding anything to the contrary set forth in this Confirmation, Seller has no obligation to deliver, and Buyer has no obligation to make a Monthly Payment for the Product for the Monthly Delivery Period if the Showing Month for the applicable month occurred before CPUC Approval. 2.4

Delivery Period

The “Delivery Period” shall be: the later of (a) October 15, 2012, or (b) the date when this Agreement has received both CPUC Approval and FERC Approval; provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition Tolling Confirmation and the Transition PPA have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), through, unless terminated earlier in accordance with the terms of this Agreement, the date that is immediately prior to the commencement of the ‘Delivery Period’ under and as defined in the RFO Agreement, which shall be no later than June 30, 2014 (the “Delivery Period End Date”); provided, however if ‘CPUC Approval’ (as defined in the RFO Agreement) and/or ‘FERC Approval’ (as defined in the RFO Agreement) of the RFO Agreement are not obtained prior to June 30, 2014, through no fault of Seller, then the Delivery Period End Date shall be June 30, 2015. 2.5

Contract Quantity

The Contract Quantity for each day of each applicable Showing Month is as follows:

6

2012 CHP RA Capacity

Generating Unit # 2 Contract Quantity (MWs) Showing Month

2012

Generating Unit # 4 Contract Quantity (MWs)

2013

2014

2015

January

74

74

74

February

74

74

March

74

April

Showing Month

2012

2013

2014

2015

January

74

74

74

74

February

74

74

74

74

74

March

74

74

74

74

74

74

April

74

74

74

May

74

74

74

May

74

74

74

June

74

74

74

June

74

74

74

July

74

74

July

74

74

August

74

74

August

74

74

September

74

74

September

74

74

October

74

74

74

October

74

74

74

November

74

74

74

November

74

74

74

December

74

74

74

December

74

74

74

ARTICLE 3 DELIVERY OBLIGATIONS 3.1

Delivery of Product

Subject to any reductions set forth in Section 3.2 (if Section 2.3 above is selected), Seller shall provide Buyer with the Contract Quantity of Product for each day of each Showing Month consistent with the following: (a)

Seller shall, on a timely basis, submit, or cause each Generating Unit's SC to submit, Supply Plans in accordance with the Tariff to identify and confirm the Unit Quantity provided to Buyer for each day of each Showing Month so that the total amount of Unit Quantity identified and confirmed for each day of such Showing Month equals the Contract Quantity for such day of such Showing Month, unless specifically requested not to do so by the Buyer.

(b)

Seller shall cause each Generating Unit’s SC to submit written notification to Buyer, no later than fifteen (15) Business Days before the relevant deadline for any applicable RAR Showing, Local RAR Showing or Flexible RAR Showing, that Buyer will be credited with the Unit Quantity for each day of the Showing Month in the Generating Unit’s SC Supply Plan so that the total amount of Unit Quantity for each day of such Showing Month credited equals the Contract Quantity.

7

2012 CHP RA Capacity

3.2

Adjustments to Contract Quantity

In the event that Section 2.3 is applicable, then: (a)

Seller’s obligation to deliver the Contract Quantity of Product for each day of each Showing Month may be reduced if any portion of the Generating Unit(s) is scheduled for a Planned Outage during that month for the applicable days of such Planned Outage; provided, Seller notifies Buyer, no later than fifteen (15) Business Days before the relevant deadline for the corresponding RAR Showing, Local RAR Showing or Flexible RAR Showing applicable to that Showing Month, the amount of Product from each Generating Unit Buyer is permitted to include in Buyer’s RAR Showing, Local RAR Showing or Flexible RAR Showing applicable to that month as a result of such Planned Outage. In the event Seller is unable to provide the Contract Quantity for any portion of a Showing Month because of a Planned Outage of a Generating Unit, Seller has the option, but not the obligation, to provide Product from Replacement Units; provided, Seller provides and identifies such Replacement Units consistent with Section 5.1. In addition, if Seller chooses not to provide Product from Replacement Units and a Generating Unit is on a Planned Outage for any portion of the applicable Showing Month, then, the Contract Quantity shall be revised in accordance with any applicable adjustments stipulated by the CPUC Filing Guide or CAISO guidelines in effect for the applicable portion of the Showing Month in which the Planned Outage occurs.

(b)

3.3

Reductions in Unit NQC: In the event the Generating Unit experiences a reduction in Unit NQC as determined by the CAISO; Seller has the option, but not the obligation, to provide the Unit Quantity from the same Generating Unit; provided the Generating Unit has sufficient remaining and available Product.

Buyer’s Re-Sale of Product

Buyer may re-sell all or a portion of the Product acquired hereunder. 3.4

Post-Showing Replacement Capacity

In the event CAISO determines, in accordance with the Tariff, that any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any portion of a Showing Month which was shown by Buyer in its RAR Showings, Local RAR Showings or Flexible RAR Showings requires outage replacement in accordance with Section 40.7 of the Tariff (“Shortfall Capacity”), (i) Seller’s Monthly Payment will be reduced in accordance with Section 4.1 below and, neither Seller, nor the Generating Unit’s SC (unless the Generating Unit’s SC is Buyer), shall have the right to provide Buyer with RA Replacement Capacity with respect to such Shortfall Capacity, (ii) Seller shall have no liability under Sections 5.2 or 5.3 below with respect to such Shortfall Capacity, except to the extent described in Section 10.3 below and (iii) Seller shall have no liability to Buyer for any costs which are allocated to Buyer by the CAISO for any RA Maintenance Outage Backstop Capacity procured by CAISO which was related to such Shortfall Capacity, except to the extent described in Section 10.3 below. Notwithstanding anything to the contrary in this Agreement, at any time that any of the proposed amendments to the Tariff relating to outage replacement, filed by the CAISO at FERC on September 20, 2012 (Docket ER 12-2669-000), have not been authorized by FERC, the provisions of this Section 3.4 shall not be applicable, and, for purposes of calculating Seller’s Monthly Payment under Section 4.1, “D” (Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month) shall equal zero.

8

2012 CHP RA Capacity

ARTICLE 4 PAYMENT 4.1

Monthly Payment

In accordance with the terms of Article Six of the Transition Master Agreement, Buyer shall make a Monthly Payment to Seller for each Generating Unit, after the applicable Showing Month, as follows:

Monthly Payment = (A x B x 1,000) where: A = applicable Contract Price for that Showing Month B= C = Contract Quantity provided by Seller to Buyer pursuant to and consistent with Section 3.1 for the applicable day of the Showing Month D = Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month i = Each day of Showing Month n = number of days in the Showing Month The Monthly Payment calculation shall be rounded to two decimal places. CAPACITY FLAT PRICE TABLE

4.2

Contract Year

RA Capacity Flat Price ($/kW-month)

2012

1.18

2013

1.18

2014

1.18

2015

1.18

Allocation of Other Payments and Costs (a)

Seller shall retain any revenues it may receive from and pay all costs charged by the CAISO or any other third party with respect to any Generating Unit for (i) start-up, shutdown, and minimum load costs, (ii) capacity revenue for ancillary services, (iii) energy sales, and (iv) any revenues for black start or reactive power services.

(b)

Buyer shall be entitled to receive and retain all revenues associated with the Contract Quantity of Product during the Delivery Period (including any capacity revenues from RMR Contracts for any Generating Unit, Capacity Procurement Mechanism (CPM), or its successor, and Residual Unit Commitment (RUC) Availability Payments, or its successor, but excluding payments described in Section 4.2(a)(i)-(iv) above).

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2012 CHP RA Capacity

(c)

In accordance with Section 4.1 of this Confirmation and Article Six of the Transition Master Agreement, (i) all such Buyer revenues described in this Section 4.2, but received by Seller, or a Generating Unit’s SC, owner, or operator shall be remitted to Buyer, and Seller shall pay such revenues to Buyer if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Buyer. If Seller fails to pay such revenues to Buyer, Buyer may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts Buyer may owe to Seller under this Confirmation. In order to verify the accuracy of such revenues, Buyer shall have the right, at its sole expense and during normal working hours after reasonable prior notice, to hire an independent third party reasonably acceptable to Seller to audit any documents, records or data of Seller associated with the Contract Quantity; and (ii) all such Seller, or a Generating Unit’s SC, owner, or operator revenues described in this Section 4.2, but received by Buyer shall be remitted to Seller, and Buyer shall pay such revenues to Seller if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Seller. If Buyer fails to pay such revenues to Seller, Seller may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts it may owe to Buyer under this Confirmation.

(d)

If a centralized capacity market develops within the CAISO region, Buyer will have exclusive rights to offer, bid, or otherwise submit the Contract Quantity provided to Buyer pursuant to this Confirmation for re-sale in such market, and retain and receive any and all related revenues.

(e)

Seller agrees that the Generating Units are subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account.

ARTICLE 5 SELLER'S FAILURE TO DELIVER CONTRACT QUANTITY 5.1

Seller’s Duty To Provide Replacement Capacity

Subject to any adjustments made pursuant to Section 3.2(a) (if Section 2.3 above is selected), if Seller is unable to provide the full Contract Quantity of Product for day of any Showing Month, then: (a)

Seller may, at no cost to Buyer, provide Buyer with replacement Product from one or more Replacement Units, such that the total amount of Product provided to Buyer from all Generating Units and Replacement Units for each day of the Showing Month equals the Contract Quantity; provided, that (i) replacement Product from any generating unit other than the generating units described in Section 5.1(a)(ii) may only be provided with Buyer’s consent, which may not be unreasonably or untimely withheld, and (ii) replacement Product from any of Seller’s generating units subject to the Transition PPA may only be provided with Buyer’s consent, which Buyer may give or withhold in Buyer’s sole discretion; and

(b)

Seller shall identify Replacement Units meeting the above requirements no later than fifteen (15) Business Days before the relevant deadline for Buyer's RAR Showing, Local RAR Showing and/or Flexible RAR Showing, provided, that the designation of any Replacement Unit by Seller shall be subject to Buyer’s prior written approval. Once

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2012 CHP RA Capacity

Seller has identified in writing any Replacement Units that meet the requirements of this Section 5.1, any such Replacement Unit shall be automatically deemed a Generating Unit for purposes of this Confirmation for that Showing Month. 5.2

Damages for Failure to Provide Replacement Capacity

If either Section 2.2 or 2.3 is selected above and Seller fails to provide Buyer any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any day of any Showing Month or if Seller has elected to provide replacement Product in accordance with the terms of this Confirmation, but fails to provide such replacement Product from one or more Replacement Units for any Showing Month, then, in each case, the following shall apply:

5.3

(a)

Buyer may, but shall not be required to, replace any portion of the Contract Quantity not provided by Seller for any portions of each Showing Month with capacity having equivalent Capacity Attributes as the Product not provided by Seller (“Replacement Capacity”). Buyer may enter into purchase transactions with one or more parties to replace the portion of Contract Quantity not provided by Seller for all portions of each Showing Month. Additionally, Buyer may enter into one or more arrangements to repurchase its obligation to sell and deliver the capacity to another party, and such arrangements shall be considered the procurement of Replacement Capacity. Buyer shall act in a commercially reasonable manner in procuring any Replacement Capacity.

(b)

Seller shall pay to Buyer at the time set forth in Section 4.1 of the Transition Master Agreement, the following damages in lieu of damages specified in Section 4.1 of the Transition Master Agreement: an amount equal to the positive difference, if any, between (i) the sum of (A) the actual cost paid by Buyer for any Replacement Capacity, including any transaction costs and expenses incurred in connection with such procurement, plus (B) each Capacity Replacement Price times the aggregate amount of the Contract Quantity neither provided by Seller nor purchased by Buyer for all portions of the applicable Showing Month pursuant to Section 5.2(a), and (ii) the aggregate amount of Contract Quantity not provided for all applicable portions of the applicable Showing Month times the Contract Price for that month. If Seller fails to pay these damages, then Buyer may offset those damages owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement.

Indemnities for Failure to Deliver Contract Quantity

Subject to any adjustments made pursuant to Section 3.2(a), Seller agrees to indemnify, defend and hold harmless Buyer from any penalties, fines or costs assessed against Buyer by the CPUC or the CAISO, resulting from any of the following: (a)

Seller’s failure to provide any portion of the Contract Quantity, if Seller fails to replace the shortfall in Contract Quantity from Replacement Units in accordance with Section 5.1 for any portion of the Delivery Period;

(b)

Seller’s failure to provide notice of the non-availability of any portion of the Contract Quantity for any portion of the Delivery Period as required under Section 3.1; or

(c)

A Generating Unit’s SC’s failure to timely submit Supply Plans that identify Buyer’s right to the Unit Quantity purchased hereunder for each day of the Delivery Period.

With respect to the foregoing, the Parties shall use commercially reasonable efforts to minimize such penalties, fines and costs; provided, that in no event shall Buyer be required to use or change its utilization of its owned or controlled assets or market positions to minimize these penalties and fines. Seller will have no obligation to Buyer under this Section 5.3 in respect of the portion of Contract Quantity for which Seller has paid damages for Replacement Capacity. If Seller fails to pay those penalties, fines or costs, or fails to reimburse Buyer for those penalties, fines or costs, then Buyer may offset those penalties, fines or costs against any future amounts it may owe to Seller under this Confirmation.

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2012 CHP RA Capacity

ARTICLE 6 CAISO OFFER REQUIREMENTS Subject to Buyer’s request under Section 10.1, during the Delivery Period, except to the extent any Generating Unit is in an Outage or Planned Outage, Seller shall either schedule or cause the Generating Unit’s SC to schedule with, or make available to, the CAISO the Unit Quantity for each Generating Unit in compliance with the Tariff, and shall perform all, or cause the Generating Unit’s SC, owner, or operator, as applicable, to perform all obligations under the Tariff that are associated with the sale of Product hereunder. Buyer shall have no liability for the failure of Seller or the failure of any Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance, provided that Buyer in its capacity as SC shall remain liable for any failure by it to comply with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 7 PLANNED OUTAGES Upon the Confirmation Effective Date, thirty (30) days before the applicable year-ahead showing, and no later than January 1, April 1, July 1 and October 1 of each calendar year thereafter until the end of the Term, Seller shall submit, or cause the Generating Unit's SC to submit to Buyer, the portion of each Generating Unit's schedule of proposed Planned Outages (“Outage Schedule”) for the following twelve (12) month period or until the end of the Delivery Period, whichever is shorter. Within twenty (20) Business Days after its receipt of an Outage Schedule, Buyer shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Good Utility Practices, accommodate Buyer's requests regarding the timing of any Planned Outage. Seller or the Generating Unit's SC shall notify Buyer within five (5) Business Days of any change to the Outage Schedule.

ARTICLE 8 OTHER BUYER AND SELLER COVENANTS 8.1

Seller’s and Buyer’s Duty to Take Action to Allow the Utilization of the Product

Buyer and Seller shall, throughout the Delivery Period, take all commercially reasonable actions and execute any and all documents or instruments reasonably necessary to ensure Buyer's right to the use of the Contract Quantity for the sole benefit of Buyer's RAR, Local RAR and Flexible RAR, if applicable. The Parties further agree to negotiate in good faith to make necessary amendments, if any, to this Confirmation to conform this Transaction to subsequent clarifications, revisions, or decisions rendered by the CPUC, FERC, CAISO or other Governmental Body having jurisdiction to administer RAR, Local RAR or Flexible RAR, to maintain the benefits of the bargain struck by the Parties on the Confirmation Effective Date. As soon as possible, but no later than 30 days prior to the Delivery Period, Seller shall provide the Unit NQC and CAISO Resource ID for each of the Generating Units subject to the terms and conditions of this Confirmation. 8.2

Seller’s Represents, Warrants and Covenants

Seller represents, warrants and covenants to Buyer that, throughout the Delivery Period and to the extent such Generating Unit is then subject to the obligations of this Confirmation: (a)

Seller owns or has the exclusive right to the Product sold under this Confirmation from each Generating Unit, and shall furnish Buyer, CAISO, CPUC or other Governmental

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2012 CHP RA Capacity

Body with such evidence as may reasonably be requested to demonstrate such ownership or exclusive right; (b)

No portion of the Contract Quantity has been committed by Seller to any third party in order to satisfy RAR Local RAR or Flexible RAR or analogous obligations in any CAISO or non-CAISO markets, other than pursuant to an RMR Contract between the CAISO and either Seller or the Generating Unit’s owner or operator;

(c)

Each Generating Unit is connected to the CAISO Controlled Grid, is within the CAISO Control Area, and is under the control of CAISO;

(d)

Seller shall, and each Generating Unit’s SC, owner and operator is obligated to, comply with Applicable Laws, including the Tariff, relating to the Product;

(e)

If Seller is the owner of any Generating Unit, the aggregation of all amounts of Capacity Attributes that Seller has sold, assigned or transferred for any Generating Unit does not exceed the Unit NQC for that Generating Unit;

(f)

Seller has notified the SC of each Generating Unit that (i) Seller has transferred the Unit Quantity with respect to each day of each Showing Month to Buyer, and (ii) the SC is obligated to deliver the Supply Plans in accordance with the Tariff;

(g)

Seller has notified the SC of each Generating Unit that Seller is obligated to cause each Generating Unit’s SC to provide to the Buyer, at least fifteen (15) Business Days before the relevant deadline for each RAR Showing, Local RAR Showing or Flexible RAR Showing, the Unit Quantity for each day of such Showing Month of each Generating Unit which is subject to the obligations of this Confirmation that is to be submitted in the Supply Plan associated with this Confirmation for the applicable period;

(h)

Seller has notified each Generating Unit’s SC that (i) Buyer is entitled to the revenues set forth in Section 4.2 and (ii) such SC is obligated to promptly deliver those revenues to Buyer, along with appropriate documentation supporting the amount of those revenues; and

(i)

Buyer shall have no liability for the failure of Seller or the failure of the Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance.

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2012 CHP RA Capacity

8.3

CHP Program Provisions; CPUC Approval; FERC Approval (a)

CHP Program Procurement and Seller Eligibility Seller and Buyer acknowledge and agree that Buyer is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by Buyer pursuant to this Confirmation is and shall be deemed by the Parties to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to Buyer that as of the Confirmation Effective Date, Generating Unit # 2 and Generating Unit # 4, together with the generating units that are subject to the obligations in the Transition PPA is a Qualifying Facility.

(b)

CPUC Approval (i) Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party. (ii) Failure to obtain CPUC Approval in accordance with this Section 8.3(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval.

(c)

Provision of Information Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement.

(d)

FERC Approval (i) Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereunder, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis

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2012 CHP RA Capacity

for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report. (ii) Failure to obtain FERC Approval in accordance with this Section 8.3(d) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

ARTICLE 9 CONFIDENTIALITY Notwithstanding Section 10.11 of the Transition Master Agreement, the Parties agree that Buyer may disclose the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to any Governmental Body, the CPUC, the CAISO in order to support its Local RAR Showings, RAR Showings or Flexible RAR Showings, if applicable, and Seller may disclose the transfer of the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to the SC of each Generating Unit in order for such SC to timely submit accurate Supply Plans; provided, that each disclosing Party shall use reasonable efforts to limit, to the extent possible, the ability of any such applicable Governmental Body, CAISO, or SC to further disclose such information. In addition, in the event Buyer resells all or any portion of the Product to another party, Buyer shall be permitted to disclose to the other party to such resale transaction all such information necessary to effect such resale transaction.

ARTICLE 10 GENERATING UNIT SUBSTITUTION 10.1

Substitute Capacity

No later than five (5) Business Days before the relevant deadline for each RAR Showing, Local RAR Showing or Flexible RAR Showing, Buyer may request that Seller not list, or cause each Generating Unit’s SC not to list, a portion or all of a Generating Unit’s Unit Quantity for any portion of a Showing Month on the Supply Plan. The amount of Unit Quantity that is the subject of such a request shall be known as “Substitute Capacity” and, for purposes of calculating a Monthly Payment pursuant to Section 4.1, be deemed Unit Quantity provided consistent with Section 3.1. Seller shall, or shall cause each Generating Unit’s SC to, comply with Buyer’s request under this Section 10.1. 10.2

Seller’s Obligations With Respect to Substitute Capacity

If Buyer makes a request for Substitute Capacity, Seller shall (a) make such Substitute Capacity available to Buyer during the applicable Showing Month in order to allow Buyer to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”); and (b) take all action, or cause each Generating Unit’s SC to take all action, to allow Buyer to utilize the Substitution Rules, including, but not limited to, ensuring that the Substitute Capacity will qualify for substitution under the Substitution Rules and providing Buyer with all information needed to utilize the Substitution Rules. Seller agrees that all Substitute Capacity that is utilized under the Substitution Rules is subject to the requirements identified in Article 6 as if the capacity had been included on the Supply Plan. 10.3

Failure to Provide Substitute Capacity

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2012 CHP RA Capacity

If Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitute Capacity under the Substitution Rules, then Seller shall pay for any and all Non-Availability Charges incurred by Buyer for such failure or inability to utilize the Substitution Rules; provided, that if Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitution Rules, in each case, because the Substitute Capacity does not qualify for substitution under the last sentence of Section 40.9.4.2.1(1) of the Tariff or under the last sentence of Section 40.9.4.2.1(2) of the Tariff, then Seller shall not be responsible for any such Non-Availability Charges described in this Section 10.3 associated with such inability. If Seller fails to pay any Non-Availability Charges under this Section 10.3, then Buyer may offset those charges owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement. 10.4

Notwithstanding anything to the contrary in this Confirmation, Article 10 shall not apply to this Confirmation at any time during which Buyer is the SC.

ARTICLE 11 MARKET BASED RATE AUTHORITY Seller agrees, in accordance with FERC Order No. 697, to, upon request of Buyer, submit a letter of concurrence in support of any affirmative statement by Buyer that this contractual arrangement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR § 35.42. Seller also agrees that it will not, in any filings, if any, made subject to Order Nos. 652 and 697, claim that this contractual arrangement conveys ownership or control of generation capacity from Seller to Buyer.

ARTICLE 12 COLLATERAL REQUIREMENTS 12.1

Seller Collateral Requirements

Notwithstanding anything to the contrary contained in the Transition Master Agreement, Seller shall provide to, and maintain with, Buyer a Full Floating Independent Amount as long as Seller or its Guarantor, if any, does not maintain Credit Ratings of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency. The Full Floating Independent Amount shall be equal to 20% of the sum of the Monthly Payments for the current month and all remaining months of the Delivery Period, without the reductions specified in Section 3.2. For the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Seller shall be added to the Exposure Amount for Buyer and subtracted from the Exposure Amount for Seller. 12.2

Current Mark-to-Market Value

The Parties further agree that for the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, the Current Mark-to-Market Value for this Transaction is deemed to be zero. If at any time prior to the expiration of the Delivery Period, a liquid market for an RA Capacity product develops wherein price quotes for such a product can be obtained, the Parties agree to amend the Confirmation to include a methodology for calculating the Current Mark-to-Market Value for this Transaction, consequently affecting the Buyer’s Exposure. 12.3

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEI Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement

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2012 CHP RA Capacity

APPENDIX A GENERATING UNIT INFORMATION (a)

Generating Unit # 2 Name: Sycamore Cogeneration Company Generating Unit # 2 Location: Bakersfield, California Resource Type: Other- Frame7E Resource Category (1, 2, 3 or 4): 4 Point of interconnection with the CAISO Controlled Grid (“Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): South Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour

(b)

Generating Unit # 4 Name: Sycamore Cogeneration Company Generating Unit # 4 Location: Bakersfield, California Resource Type: Other- Frame7E Resource Category (1, 2, 3 or 4): 4 Point of interconnection with the CAISO Controlled Grid (“Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): South Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour

18

Appendix B

EEI Master Agreement Cover Sheet SCE version09.12.11

[THIS MASTER AGREEMENT IS SUBJECT TO SCE MANAGEMENT REVIEW AND APPROVAL1]MASTER POWER PURCHASE AND SALE AGREEMENT COVER SHEET This Master Power Purchase and Sale Agreement (Version 2.1; modified 4/25/00) (“Master Agreement” or “Transition Master Agreement”) is made as of the following date: ________________2October 15, 2012 (“Effective Date”). The Transition Master Agreement, together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support, margin agreement, or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the “Agreement”. The Parties to this Transition Master Agreement are the following: Name: ___________________________Kern River Cogeneration Company (“Party A”)

Name: Southern California Edison Company (“Party B”)

All Notices:

All Notices:

Street: P. O. Box 80598

Street: 2244 Walnut Grove Ave., G.O.1, Quad 1C

City: Bakersfield

1 2

City: Rosemead, CA

Zip: 93380

Zip: 91770

Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610 Duns: 17-357-0292 Federal Tax ID Number: 95-3880295

Attn: Contract Administration Phone: (626) 302-3126 Facsimile: (626) 302-8168 Duns: 006908818 Federal Tax ID Number: 95-1240335

Invoices: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Invoices: Attn: Power Procurement - Finance Phone: (626) 302-3277 Facsimile: (626) 302-3276 Email: [email protected]@sce.co m

Scheduling: Attn: Control Room Phone: 661-615-4639 Facsimile: 661-615-4623

Scheduling: Attn: Manager of Energy Operations Phone: (626) 302-5730 Facsimile: (626) 307-4413

Payments: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Payments: Attn: Accounts Receivable - Power Procurement Southern California Edison Company PO Box 800 Rosemead, CA 91770 Phone: (626) 302-9371 Facsimile: (626) 302-9392

Wire Transfer: BNK: JP Morgan Chase ABA: 021-0000-21 ACCT: 910-2588-697

Wire Transfer: BNK: JPMorganChaseJPMorgan Chase Bank ABA: 021000021 ACCT: 323-394434

[SCE Comment: Green highlights are comments or instructions to be deleted prior to final execution.] [SCE Comment: Blue highlights indicate required information to be completed prior to final execution.] 11

EEI Master Agreement Cover Sheet SCE version09.12.11

Credit and Collections: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Credit and Collections: Attn: Manager of Credit Phone: (626) 302-3383 Facsimile: (626) 302-2517

Confirmations: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

Confirmations: Attn: Confirmation Coordinator Phone: (626) 307-4485 Facsimile: (626) 302-3410

With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

With additional Notices of an Event of Default or Potential Event of Default to: Southern California Edison Company 2244 Walnut Grove Ave., G.O.1, Quad 1C Rosemead, CA 91770 Attn: Manager of Energy Contracts Phone: (626) 302-3312 Facsimile: (626) 302-8168

The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions: Party A Tariff

Tariff Original Volume No. 1

Party B Tariff

Tariff Original Vol. No. 8

Dated March 21, 2010 Docket Number ER10-611-000 Dated 09/01/2002

22

Docket Number ER 02-2263-000

EEI Master Agreement Cover Sheet SCE version09.12.11

Article Two Transaction Terms and Conditions

Optional provision in Section 2.4. If not checked, inapplicable.

Article Four Remedies for Failure to Deliver or Receive

Accelerated Payment of Damages. If not checked, inapplicable.

Article Five Events of Default; Remedies

5.1(g) Cross Default for Party A: Party A: Kern River Cogeneration Company Other Entity:[Guarantor, if applicable]

Cross Default Amount $________ [Amount and/or Methodology To Be Negotiated]1,000,000 Cross Default Amount $_____NA___ [Amount and/or Methodology To Be Negotiated]

5.1(g) Cross Default for Party B: Party B: Southern California Edison Company.

Cross Default Amount $________ [Amount and/or Methodology To Be Negotiated]75,000,000

Other Entity: Not Applicable.

Cross Default Amount $________ [Amount and/or Methodology To Be Negotiated]

5.6 Closeout Setoff Option A, as amended. Option B - Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows: Option C (No Setoff). Article Eight

[ARTICLE EIGHT PROVISIONS TO BE NEGOTIATED BY CREDIT GROUPS]

Credit and Collateral Requirements

8.1 Party A Credit Protection: (a) Financial Information: Option A, as amended. Option B Specify: Option C Specify:

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(b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex.

(d) Downgrade Event: Not Applicable. Applicable. If applicable, complete the following: It shall be a Downgrade Event for Party B if Party B’s Credit Rating falls below ______ from S&P or _________ from Moody's or ______ from Fitch or if Party B is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party B: Not Applicable. Guarantee Amount: Not Applicable. 8.2 Party B Credit Protection: (a) Financial Information: Option A, as amended. Option B, as amended. Specify: [Guarantor or other party specified, if applicable]________________ Option C Specify: ___________ (b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex. (d) Downgrade Event: Not Applicable. Applicable.

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If applicable, complete the following: It shall be a Downgrade Event for Party A if Party A’s Credit Rating falls below ___ from S&P or ___ from Moody's or ______ from Fitch or if Party A is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party A: Guarantee Amount: $__________ Article Ten Confidentiality Schedule M

Confidentiality Applicable. If not checked, inapplicable. Party A is a Governmental Entity or Public Power System. Party B is a Governmental Entity or Public Power System. Add Section 3.6. If not checked, inapplicable. Add Section 8.4. If not checked, inapplicable.

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Other Changes

The following changes shall be applicable. ARTICLE ONE: GENERAL DEFINITIONS. Amend Article One as follows: Section 1.4 is amended by (i) deleting the word “or” in the first line, and (ii) inserting the words “, or the Friday immediately following the U.S. Thanksgiving holiday” immediately after “Bank holiday”. Section 1.11 is amended by (i) deleting the words “attorneys’ fees and” and (ii) inserting the words “(excluding attorneys’ fees)” after the word “expenses” in the fifth line. Section 1.12 is amended by replacing the word “issues” in the fourth line with the word “issuer”, and replacing the phrase “S&P, Moody’s or any other rating agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement” with the phrase “the Ratings Agencies”. Section 1.24 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.27 is amended to read as follows: “1.27 ‘Letter of Credit’ means an irrevocable, nontransferable standby letter of credit, issued by a major U.S. commercial bank or the U.S. branch office of a foreign bank with, in either case, a Credit Rating of at least (a) A- by S&P, A3 by Moody’s, and A- by Fitch, if such entity is rated by the Ratings Agencies; or (b) A- by S&P, A3 by Moody’s, or A- by Fitch, if such entity is rated by only one or two of the Ratings Agencies, in substantially the form attached hereto as Schedule 1, with such changes to the terms in that form as the issuing bank may require and as may be acceptable to the beneficiary thereof. Costs of a Letter of Credit shall be borne by the applicant for such Letter of Credit.” Section 1.28 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.29 is amended by inserting the words “or ‘Transition Master Agreement’ ” immediately after “Master Agreement”. Section 1.50 is amended by replacing the term “Section 2.4” with the term “Section 2.5”. Section 1.51 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, from an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Buyer’s option,” the phrase “absent a purchase from an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. Section 1.53 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, to an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Seller’s option,” the phrase “absent a sale to an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. New Sections 1.62, 1.63, 1.64, 1.65, 1.66, 1.67, 1.68, 1.69, 1.70, 1.71 and 1.681.72

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are added to read as follows: “1.62 ‘CPUC Approval’ means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement and the Transition PPA in their respective entirety, including payments to be made by Party B, subject to CPUC review of Party B’s administration of each of the Agreement and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and nonappealable.” “1.63 ‘FERC Approval’ means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.7(a) of this Agreement in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal.” “1.64 ‘Fitch’ means Fitch Ratings Ltd. or its successor.” “1.65 ‘Forward Price Assessments’ means quotations solicited or obtained in good faith from regularly published and widely-distributed forward price assessments from a broker that is not an Affiliate of either Party and who is actively participating in markets for the relevant Products.” “1.631.66 ‘Market Quotation Average Price’ means the arithmetic mean of the quotations solicited in good faith from not less than three (3) Reference MarketMakers (as hereinafter defined); provided, however, that the Party obtaining the quotes shall use reasonable efforts to obtain good faith quotations from at least five (5) Reference Market-Makers and, if at least five (5) such quotations are obtained, the Market Quotation Average Price shall be determined by disregarding the highest and lowest quotations and taking the arithmetic mean of the remaining quotations. The quotations shall be based on the offers to sell or bids to buy, as applicable, obtained for transactions substantially similar to each Terminated Transaction. The quote must be obtained assuming that the Party obtaining the quote will provide sufficient credit support for the proposed transaction. Each quotation shall be obtained in good faith by such Party, to the extent reasonably practicable, as of the same day and time (without regard to different time zones) on or as soon as reasonably practicable after the relevant Early Termination Date, such day and time as of which those quotations will be selected shall be specified in accordance with Section 5.2. If fewer than three (3) quotations are obtained, it will be deemed that the Market Quotation Average Price in respect of such Terminated Transaction or group of Terminated Transactions cannot be determined.” “1.641.67 ‘Merger Event’ means, with respect to a Party or its Guarantor, that

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such Party or its Guarantor consolidates or amalgamates with, merges into or with, or transfers substantially all its assets to another entity and (i) the resulting entity fails to assume all the obligations of such Party hereunder or of such Party’s Guarantor under its guaranty, or (ii) the benefits of any credit support provided by such Party pursuant to Article Eight, or any guaranty provided by such Party’s Guarantor, fail to extend the performance by such resulting, surviving or transferee entity of its obligations hereunder, or (iii) the resulting entity’s creditworthiness is materially weaker than that of such Party or its Guarantor immediately prior to such action. The creditworthiness of the resulting entity shall not be deemed to be ‘materially weaker’ so long as the resulting entity maintains a Credit Rating of at least that of the applicable Party or its Guarantor, as the case may be, immediately prior to the consolidation, merger or transfer.” “1.651.68 ‘Ratings Agency’ means any of S&P, Moody’s, and Fitch, and any other ratings agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement (collectively the ‘Ratings Agencies’).” “1.661.69 ‘Reference Market-Maker’ means a leading dealer in the relevant market that is not an Affiliate of either Party and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker.” “1.671.70 ‘Specified Energy Transaction’ means the Transition PPA or any transaction (including an agreement with respect to any such transaction) now existing or hereafter entered into between Party A and Party B (or any Guarantor of such Party) which is not a Transaction under this Agreement, but which is a transaction under the International Swaps and Derivatives Association Master Agreement, the North American Energy Standards Board Base Contract for Purchase and Sale of Natural Gas, the WSPP Agreement, or under any other agreement with respect to the purchase, sale, or transfer of (a) wholesale physical electric energy or capacity; (b) wholesale physical natural gas; or (c) financial derivative products related thereto.” “1.68 ‘Fitch’ means Fitch Ratings Ltd. or its successor.”1.71 ‘Transition Collateral Annex’ has the meaning set forth in Section 5.1(e).” “1.72 ‘Transition PPA’ means that certain Power Purchase and Sale Agreement, dated October 15, 2012, between Party A and Party B, as may be amended from time to time.”

ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS. Amend Article Two as follows: Section 2.1 is amended by adding the following sentence to the end thereof “Any Transaction formed and effectuated pursuant to the foregoing shall be considered a ‘writing’ or ‘in writing’ and to have been ‘signed’ by each Party or otherwise binding on the Parties.” Section 2.2 is amended to delete the second comma after the words “supplements hereto),” and before “the Party” in the second sentence. Section 2.4 is amended by (i) deleting the words “either orally or” after the phrase

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“Section 2.3 unless agreed to” in the second to last line thereof. Section 2.5 is amended (i) to delete the phrase “Unless a Party expressly objects to a Recording (defined below) at the beginning of a telephone conversation,”; (ii) by capitalizing the word “each” in the first sentence; and (iii) replacing the words “Parties to this Master Agreement” with “Parties’ trading and marketing personnel”. A new Section 2.6 is added to read as follows: “2.6 Imaged Agreement. Any original executed Transition Master Agreement, Confirmation or other related document may be photocopied and stored on computer tapes and disks (the ‘Imaged Agreement’). The Imaged Agreement, if introduced as evidence on paper, the Confirmation, if introduced as evidence in automated facsimile form, the Recording, if introduced as evidence in its original form and as transcribed onto paper or into other written format, and all computer records of the foregoing, if introduced as evidence in printed format, in any judicial, arbitration, mediation or administrative proceedings, will be admissible as between the Parties to the same extent and under the same conditions as other business records originated and maintained in documentary form. Neither Party shall object to the admissibility of the Recording, the Confirmation, or the Imaged Agreement (or photocopies of the transcription of the Recording, the Confirmation, or the Imaged Agreement) on the basis that such were not originated or maintained in documentary or written form under either the hearsay rule or the best evidence rule. However, nothing in this Section 2.6 shall preclude a Party from challenging the admissibility of such evidence on some other grounds, including, without limitation, the basis that such evidence has been materially or substantially altered from the original.” A new Section 2.7 is added to read as follows: “2.7 Conditions Precedent.

(a) Within sixty (60) days of the Effective Date, Party B and Party A shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Party A nor Party B shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Party A the authority to sell the Product to Party B at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within thirty (30) calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Party B shall make best efforts to provide Party A with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within fifty (50) days after the Effective Date; provided that if Party B is unable to provide Party A with a draft of the public version of such independent evaluator report within 50 days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Party B provides

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Party A such independent evaluator report.

(b) Within sixty (60) days after the Effective Date, Party B shall file with the CPUC the appropriate request for CPUC Approval. Party B shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Party A shall use reasonable efforts to support Party B in obtaining CPUC Approval. Party B has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(c) Notwithstanding Party A’s and Party B’s execution and delivery of this Agreement, no Transaction under this Agreement will be permitted or deemed valid until the Parties obtain FERC Approval and Party B obtains CPUC Approval.

(d) Notwithstanding anything to the contrary set forth in this Agreement, no Transaction under this Agreement will be permitted or deemed valid until all of the condition precedents set forth in the Transition PPA have been satisfied or waived in accordance with the terms of the Transition PPA.” A new Section 2.8 is added to read as follows: “2.8 Termination Rights of the Parties; Automatic Termination.

(a) If the Transition PPA is terminated before the commencement of the Term Start Date of the Transition PPA (including if such termination is due to the inability to obtain FERC Approval or CPUC Approval), then this Agreement (including any Transaction and related Confirmation entered into between Party A and Party B as of the Effective Date) will automatically terminate on the date of the termination of the Transition PPA.” ARTICLE THREE: OBLIGATIONS AND DELIVERIES. Amend Article Three as follows: A new Section 3.4 is added to read as follows: “3.4 Index Transactions. If the Contract Price for a Transaction is determined by reference to an index, then the following provisions shall be applicable to such Transaction. (a)

Market Disruption. If a Market Disruption Event occurs during a Determination Period, the Floating Price for the affected Trading Day(s) shall be determined by reference to the Floating Price specified in the Transaction for the first Trading Day thereafter on which no Market Disruption Event exists; provided, however, if the Floating Price is not so determined within three (3) Business Days after the first Trading Day on which the Market Disruption Event occurred or existed, then the Parties shall negotiate in good faith to agree on a Floating Price (or a method for determining a Floating Price), and if the Parties have not so agreed on or before the twelfth Business Day following the first Trading Day on which the Market Disruption Event occurred or existed, then the Floating Price shall be determined in good faith by taking the average of the price quotations for the relevant commodity and relevant Business Days that are

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obtained from no more than two (2) Reference Market-Makers selected by each Party. (b) For purposes of this Section 3.4, the following definitions shall apply: (i) ‘Determination Period’ means each calendar month a part or all of which is within the Delivery Period of a Transaction. (ii) ‘Exchange’ means, in respect of a Transaction, the exchange or principal trading market specified in the relevant Transaction. (iii) ‘Floating Price’ means a price per unit in $U.S. specified in a Transaction that is based upon a Price Source. (iv) ‘Market Disruption Event’ means, with respect to any Price Source, any of the following events: (a) the failure of the Price Source to announce or publish the specified Floating Price or information necessary for determining the Floating price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading in the relevant options contract or commodity on the Exchange or in the market specified for determining a Floating Price; (c) the temporary or permanent discontinuance or unavailability of the Price Source; (d) the temporary or permanent closing of any Exchange specified for determining a Floating Price; or (e) a material change in the formula for or the method of determining the Floating Price. (v) ‘Price Source’ means, in respect of a Transaction, the publication (or such other origin of reference, including an Exchange) containing (or reporting) the specified price (or prices from which the specified price is calculated) specified in the relevant Transaction. (vi) ‘Trading Day’ means a day in respect of which the relevant Price Source published the Floating Price. (c) Corrections to Published Prices. For purposes of determining a Floating Price for any day, if the price published or announced on a given day and used or to be used to determine a relevant price is subsequently corrected and the correction is published or announced by the person responsible for that publication or announcement within twelve (12) months of the original publication or announcement, either Party may notify the other Party of (i) that correction and (ii) the amount (if any) that is payable as a result of that correction. If, not later than thirty (30) days after publication or announcement of that correction, a Party gives notice that an amount is so payable, the Party that originally either received or retained such amount will, not later than ten (10) Business Days after the effectiveness of that notice, pay, subject to any applicable conditions precedent, to the other Party that amount, together with interest at the Interest Rate for the period from and including the day on which payment originally was (or was not) made to but excluding the day of payment of the refund or payment resulting from that correction. (d) Calculation of Floating Price. For the purposes of the calculation of a Floating Price, all numbers shall be rounded to three (3) decimal places. If the fourth (4th) decimal number is five (5) or greater, then the third (3rd) decimal number shall be increased by one (1), and if the fourth (4th) decimal number is less than five (5), then the third (3rd) decimal number shall remain

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unchanged.” ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES. Amend Article Five as follows: Section 5.1(a) is amended by replacing “three (3) Business Days” with “five (5) Business Days”. Section 5.1(e) is amended by adding after the word “hereof” the phrase “or any other credit arrangement, including, but not limited to, the Collateral Annex (the ‘Transition Collateral Annex’) (or any similar agreement) related to this Agreement”. Section 5.1(f) is amended to read as follows: “(f) a Merger Event occurs with respect to such Party or its Guarantor, if applicable;” Section 5.1(h)(iv) is amended by inserting the words “made in connection with this Agreement” after the first instance of the word “guaranty”. Section 5.1(h)(v) is amended by inserting the words “made in connection with this Agreement” after the word “guaranty”. Section 5.1 is amended by adding the following Sections 5.1(i) and 5.1(j) at the end thereof: “(i) an event of default occurs (howsoever determined) under a Specified Energy Transaction (including under the Transition PPA) with respect to such Party and, after giving effect to any applicable notice requirement or grace period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that Specified Energy Transaction; or (j) the Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, this Transition Master Agreement, any Confirmation executed and delivered by that Party, the Transition PPA or any Transaction evidenced by such a Confirmation.” Section 5.2 is amended by (i) inserting “(a)” at the beginning thereof; (ii) reversing the placement of “(i)” and “to”; (iii) inserting after the words “designate a day” the words “and time of day” in clause (i) thereof; (iv) replacing the phrase “as soon thereafter as is reasonably practicable)” with “, then each such Transaction — individually, an ‘Excluded Transaction’ and collectively, the ‘Excluded Transactions’— shall be terminated as soon thereafter as is reasonably practicable, and upon termination shall be deemed to be a Terminated Transaction) and the Termination Payment payable in connection with all Terminated Transactions shall be calculated in accordance with this Section 5.2 and with Section 5.3 below”; and (v) adding the following paragraph at the end thereof: “(b) The Non-Defaulting Party shall determine its Gains and Losses by determining the Market Quotation Average Price for each Terminated Transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts, to obtain the Market Quotation Average Price with respect to any Terminated Transaction, then the NonDefaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner by calculating the arithmetic mean of at least three (3) Forward Price Assessments for transactions substantially similar to each Terminated Transaction. In the

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event the Non-Defaulting Party is not able, after commercially reasonable efforts to obtain at least three (3) Forward Price Assessments with respect to any Terminated Transaction, then the Non-Defaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner by reference to information supplied to it by one or more third parties including, without limitation, index prices, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads, or other relevant market data in the relevant markets; provided, however, that the provider of such information shall not be an Affiliate of either Party. Only in the event the Non-Defaulting Party is not able, after using commercially reasonable efforts, to obtain such third party information, then the Non-Defaulting Party may calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner using relevant market data it has available to it internally.” Section 5.3 is amended by (i) deleting the “:” in the second line thereof; (ii) replacing the words “Agreement against” with “Agreement, against” immediately before “(b)”; and (iii) inserting the phrase “any cash then available to the Defaulting Party pursuant to Article Eight,” between the words “Non-Defaulting Party,” and “plus any” in the sixth line thereof. Section 5.4 is amended by inserting the phrase “but in no event more than fifteen (15) Business Days following the Early Termination Date,” after the phrase “liquidation,” in the second line thereof. Section 5.6 Option A is amended by (i) inserting the following phrase “with respect to the Specified Energy Transactions,” before the words “and/or (ii)” and (ii) adding the following at the end thereof : “Notwithstanding anything to the contrary contained in this Transition Master Agreement, or in any other agreement, instrument, or undertaking between the Parties with respect to a Specified Energy Transaction, if an Early Termination Date has been designated pursuant to Section 5.2, then, in addition to the other remedies provided in this Transition Master Agreement, the Non-Defaulting Party may accelerate, liquidate and terminate all, but not less than all, Specified Energy Transactions between the Parties.” Section 5.7 is amended to capitalize the word “early” in line 6 to read “Early”. ARTICLE SIX: PAYMENT AND NETTING. Amend Article Six as follows: Section 6.3 is amended to read as follows: “6.3 Disputes and Adjustments of Invoices. A Party may adjust any invoice rendered by it under this Agreement to correct any arithmetic or computational error or to include additional charges or claims within twenty-four (24) months after the close of the month in which the obligations being invoiced arose. A receiving Party may, in good faith, dispute the correctness of any invoice or of any adjustment to any invoice previously rendered to it by providing notice to the other Party on or before the later of (i) twelve (12) months of the date of receipt of such invoice or adjusted invoice, or (ii) twenty-four (24) months after the close of the month in which the obligation being invoiced arose. Failure to provide such notice within the time frame set forth in the preceding sentence waives the dispute with respect to such invoice. A Party disputing all or any part of an invoice or an adjustment to an invoice previously rendered to it may pay

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only the undisputed portion of the invoice when due, provided such Party provides notice to the other Party of the basis for and amount of the disputed portion of the invoice that has not been paid. The disputed portion of the invoice must be paid within two (2) Business Days of resolution of the dispute, along with interest accrued at the Interest Rate from and including the original due date of the invoice to but excluding the date the disputed portion of the invoice is actually paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment but excluding the date repaid or deducted by the Party receiving such overpayment. An invoice can only be adjusted or amended after it was originally rendered within the twenty-four (24) month time framesframe set forth in the first sentence of this Section 6.3. If an invoice is not rendered within twenty-four (24) months after the close of the month in which the payment obligations arose, the right to payment for that month under this Agreement is waived.” Section 6.7 is amended to replace the phrase “Section 6.1” with the phrase “Section 6.2”. ARTICLE SEVEN: LIMITATIONS. Amend Article Seven as follows: Section 7.1 is amended to (i) delete the phrase “EXCEPT AS SET FORTH HEREIN” in the first sentence; and (ii) in the fifth sentence (a) replace in its entirety the phrase “UNLESS EXPRESSLY HEREIN PROVIDED” with “NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY”; (b) add the following phrase “SET FORTH IN THIS AGREEMENT” after the words “INDEMNITY PROVISION”; and (c) add the following phrase “; PROVIDED, HOWEVER, THAT NOTHING IN THIS PROVISION SHALL AFFECT THE ENFORCEABILITY OF SECTIONS 5.2 AND 5.3 OF THIS AGREEMENT” after the words “OR OTHERWISE”. ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS. Amend Article Eight as follows: Section 8.1(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes) after the words “consolidated financial statements” in the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations, provided however, for the purposes of this (i) and (ii), if Party B’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party B’s website, then Party B shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line. [SCE comment—The following is applicable if Option A is selected] Section 8.2(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes)” after the words “consolidated financial statements” in

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the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year [if Party A is an SEC reporting company: certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations] [OR if Party A is not an SEC reporting company: certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year end audit adjustments)], provided however, for the purposes of this (i) and (ii), if Party A’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party A’s website, then Party A shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line; and (v) at the end thereof the phrase “[if Party A is not an SEC reporting company: For purposes of this Section, ‘Responsible Officer’ shall mean the Chief Financial OfficerExecutive Director, Treasurer or any Assistant Treasurer of Party A or any employee of Party A designated by any of the foregoing.]”. [SCE comment—The following is applicable if Option B is selected] Section 8.2(a) Option B is amended to add (i) the phrase “or Party A’s Guarantor [or other entity specified on the Cover Sheet]” after the words “Party A” in the first line; (ii) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes)” after the words “consolidated financial statements” in the third line; (iii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; (iv) is amended by replacing the phrase “for the party(s) specified on the Cover Sheet” with the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year [if Party A’s Guarantor [or other entity specified on the Cover Sheet] is an SEC reporting company: certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations] [OR if Party A’s Guarantor [or other entity specified on the Cover Sheet]is not an SEC reporting company: certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year end audit adjustments)], provided however, for the purposes of this (i) and (ii), if Party A’s Guarantor’s [or other entity specified on the Cover Sheet] financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party A’s Guarantor’s [or other entity specified on the Cover Sheet] website, then this requirement shall be deemed satisfied” in the fifth line; and (v) at the end thereof the phrase “[if Party A’s Guarantor [or other entity specified on the Cover Sheet] is not an SEC reporting company: For purposes of this Section, ‘Responsible Officer’ shall mean the Chief Financial Officer, Treasurer or any Assistant Treasurer of Party A’s Guarantor or any employee of Party A’s Guarantor designated by any of the foregoing.]”. A new Section 8.4 is added to read as follows: “8.4 [Uniform/California] Commercial Code Waiver. This Agreement and the Transition Collateral Annex set forth the entirety of the agreement of the Parties regarding credit, collateral and adequate assurances, in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement. Except as expressly set forth in the options elected by the Parties in respect of Sections 8.1 and 8.2, in Section 8.3, and in the relevant

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portions of the Transition Collateral Annex, neither Party: (a) has or will have any obligation to post margin, provide letters of credit, pay deposits, make any other prepayments or provide any other financial assurances, in any form whatsoever, or (b) will have reasonable grounds for insecurity with respect to the creditworthiness of a Party that is complying with the relevant provisions of Section 8 of this Transition Master Agreement and of the relevant provisions of the Transition Collateral Annex; in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement, and all implied rights relating to financial assurances arising from Section 2-609 of the [Uniform/California] Commercial Code Section 2609 or case law applying similar doctrines, are hereby waived.” ARTICLE NINE: GOVERNMENTAL CHARGES. Amend Article Nine as follows: Section 9.2, is amended to add the words “, charges, or fees” after the word “taxes” in the first line thereof. ARTICLE TEN: MISCELLANEOUS. Amend Article Ten as follows: Section 10.2(vi) is amended to add the phrase “(for purposes of this Section 10.2(vi), Party B shall be deemed to have no Affiliates)” after the word “Affiliates”. Section 10.2(x) is amended to read as follows: “(x) it is an ‘eligible commercial entity’ within the meaning of Section 1a (11) of the Commodity Exchange Act, as amended by the Commodity Futures Modernization Act of 2000 (the ‘Commodity Exchange Act’);” Section 10.2(xi) is amended to read as follows: “(xi) it is an ‘eligible contract participant’ within the meaning of Section 1a (12) of the Commodity Exchange Act; and ” Section 10.2(xii) is amended to read as follows: “(xii) each Transaction that is not executed or traded on a ‘trading facility’, as defined in Section 1(a)(33) of the Commodity Exchange Act, is subject to individual negotiation by the Parties.” Section 10.4 is amended by adding the following sentence at the end thereof: “Neither Party shall be liable with respect to any Claim to the extent that such Claim resulted from the negligence, willful misconduct, or bad faith of the indemnified Party.” Section 10.5 is amended as follows: (a) add the following phrase to the end of clause (i) immediately after the word “arrangements” the phrase “to any person or entity whose creditworthiness is equal to or higher than that of such Party”; (b) in clause (ii) replace the words “affiliate” and “affiliate’s” with, respectively “Affiliate” and “Affiliate’s”; and (c) in clause (iii) immediately after the words “substantially all of the assets” insert the words “of such Party and”.

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Section 10.6 is amended to read as follows: “10.6 Governing Law; Venue; Dispute Resolution. (a) Governing Law and Venue:. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY DISPUTE ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT. The Parties hereby consent to conduct all dispute resolution, judicial actions or proceedings arising directly, indirectly or otherwise in conjunction with, out of, related to, or arising from this Agreement in Los Angeles County, California. (b) Dispute Resolution: (i) Mediation. The Parties agree that any. Any and all disputes, claimsClaims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which disputes, claims, or controversiesDisputes the Parties have been unable to resolve by informal methods after undertaking a good faith effort to do so, shall, will first be submitted to Judicial Arbitration and Mediation Services, Inc. (‘JAMS’), its successor, or any other mutually agreeable neutral (the ‘Mediator’) for mediation in accordance with the procedures described in Section 10.6(c), and if the matterDispute is not resolved through mediation, then it shall be submitted as provided below for final and binding arbitration in accordance with the procedures described in Section 10.6(d). (c) Mediation. Either Party may initiate the mediation by providing notice to the other Party of a written request for mediation, setting forth the subjecta description of the disputeDispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the JAMS’ panel of neutrals, or in selecting a from the Judicial Arbitration and Mediation Services, Inc. or any successor entity (“JAMS”), or any other mutually acceptable non-JAMS Mediator, and such proceedings shall be conducted in accordance with the laws of the State of California, without regards to principles of conflicts of laws. Such selection and scheduling will be completed within forty-five (45) days after notice of the request for mediation. Unless the Parties agree to a different arrangement, the place of the mediation shall be in Los Angeles County, California, . Unless otherwise agreed to by the Parties, however, the mediation shallwill not be scheduled for a date that is greater than one-hundred twenty (120) days from the date of notice of the initial written request for mediation. The Parties covenant that they will participate in the mediation in good faith, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and costs shallwill be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, shallwill not be subject to discovery and shallwill be confidential, privileged and inadmissible for any

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purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them,; provided, however, that evidence that is otherwise admissible or discoverable shallwill not be rendered inadmissible or non-discoverable as a result of its use in the mediation. (iid) Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation by making a writtenin accordance with Section 10.6(c) by providing notice of a demand for binding arbitration before a single, neutral arbitrator (the ‘“Arbitrator’”) at any time following the earlier of (a) 150 days from the initial request for mediation provided above, or (b) the unsuccessful conclusion of the mediation provided for in Section 10.6(c). The Parties will cooperate with one another in promptly selecting the Arbitrator and shallwithin sixty (60) days after notice of the demand for arbitration and will further cooperate in scheduling the arbitration hearing to commence no later than one-hundred eighty (180) days from the date of notice of the initial written demand for binding arbitration. If, notwithstanding their good faith efforts,. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator shallwill be appointed as provided for in California Code of Civil Procedure Section 1281.6.1281.6, in which case each candidate for Arbitrator must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator shallwill be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon notice of a Party’s written demand for binding arbitration, such dispute, claim or controversyDispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, shallwill be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regardsregard to principles of conflicts of laws. Except as provided for hereinin this Section 10.6(d), the arbitration shallwill be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated; absent. Absent the existence of such rules and procedures, the arbitration shallwill be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). However, notwithstanding Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration shallwill be in Los Angeles County, California, each side in the arbitration shall be entitled to take up to three (3) depositions, and all direct testimony in the arbitration shall be submitted, California, and discovery will be limited as follows: (i) before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment); (ii) the initial disclosure will occur within thirty (30) days after the initial conference with the Arbitrator or at such time as the Arbitrator may order;

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(iii) discovery may commence at any time after the Parties’ initial disclosure; (iv) the Parties will not be permitted to propound any interrogatories or requests for admissions; (v) discovery will be limited to twenty-five (25) document requests (with no subparts), three (3) lay witness depositions, and three (3) expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents); (vi) each Party is allowed a maximum of three (3) expert witnesses, excluding rebuttal experts; (vii) Within sixty (60) days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding; (viii) within thirty (30) days after the initial expert disclosure, the Parties may designate a maximum of two (2) rebuttal experts; (ix) unless the Parties agree otherwise, all direct testimony will be in the form of affidavits or declarations under penalty of perjury. Each; and (x) each Party shall cooperate in makingmake available for cross-examination at the arbitration hearing its witnesses whose direct testimony has been so submitted. The Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections3.01, 3.02, 3.03, 9.09 of the Transition PPA. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator shallmust, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs shallwill be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail. Until such award is made, however, the Parties shallwill share equally in paying the costs of the arbitration. At the conclusion of the arbitration hearing, the Arbitrator shall prepare in writing and provide to each Party a decision setting forth factual findings, legal analysis, and the reasons on which the Arbitrator’s decision is based. The Arbitrator shall also have the authority to resolve claims or issues in advance of the arbitration hearing that would be appropriate for a California superior court judge to resolve in advance of trial. The Arbitrator shall not have the power to commit errors of law or fact, or to commit any abuse of discretion, that would constitute reversible error had the decision been rendered by a California superior court. The Arbitrator’s decision may be vacated or corrected on appeal to a California court of competent jurisdiction for such error. Unless otherwise agreed to by the Parties, all proceedings before the Arbitrator shall be reported and transcribed by a certified court reporter, with each Party bearing one-half of the court reporter’s fees.” Section 10.8 is amended to replace in the penultimate sentence thereof the phrase “twelve (12) months” with the phrase “two (2) years”.

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Section 10.10 is amended to read as follows: “10.10 Bankruptcy Issues. The Parties intend that (i) all Transactions constitute a ‘forward contract’ within the meaning of the United States Bankruptcy Code (the ‘Bankruptcy Code’) or a ‘swap agreement’ within the meaning of the Bankruptcy Code; (ii) all payments made or to be made by one Party to the other Party pursuant to this Agreement constitute ‘settlement payments’ within the meaning of the Bankruptcy Code; (iii) all transfers of Performance Assurance by one Party to the other Party under this Agreement constitute ‘margin payments’ within the meaning of the Bankruptcy Code and (iv) this Agreement constitutes a ‘master netting agreement’ within the meaning of the Bankruptcy Code. Each Party further agrees that, for purposes of this Agreement, the other Party is not a ‘utility’ as such term is used in 11 U.S.C. Section 366, and each Party waives and agrees not to assert the applicability of the provisions of 11 U.S.C. Section 366 in any bankruptcy proceeding wherein such Party is a debtor. In any such proceeding, each Party further waives the right to assert that the other Party is a provider of last resort to the extent such term relates to 11 U.S.C. Section 366 or another provision of 11 U.S.C. Section 101-1532.” Section 10.11 is amended to read as follows: “10.11 Confidentiality. If the Parties have elected on the Cover Sheet of the Transition Master Agreement to make this Section 10.11 applicable to this Transition Master Agreement, neither Party shall disclose the terms or conditions of this Agreement to a third party (other than the Party’s or the Party’s Affiliates’ officers, directors, employees, lenders, counsel, accountants, advisors, or rating agencies who have a need to know such information and have agreed to keep such terms confidential) except (i) in order to comply with any applicable law, order, regulation, ruling, summons, subpoena, exchange rule, or accounting disclosure rule or standard, or to make any showing required by any applicable governmental authority; (ii) to the extent necessary for the enforcement of this Agreement or to implement any Transaction; (iii) as may be obtained from a non-confidential source that disclosed such information in a manner that did not violate its obligations to the non-disclosing Party or its Guarantor in making such disclosure; (iv) to the extent such disclosure to a third party is for the sole purpose of calculating a published index, so long as such third party (1) has agreed prior to the disclosure to protect the specific information disclosed from public disclosure and (2) is a party engaged in the business of collecting such information for the purpose of establishing, creating, or formulating a published index; (v) to the extent such information is or becomes generally available to the public prior to such disclosure by a Party; (vi) when required to be released in connection with any regulatory proceeding (provided that the releasing Party makes reasonable efforts to obtain confidential treatment of the information being released); or (vii) with respect to Party B, as may be furnished to its duly authorized regulatory and governmental agencies or entities, including without limitation the California Public Utilities Commission (the “CPUC”) and all divisions thereof, and to Party B’s Procurement Review Group (the “PRG”), a group of participants including members of the CPUC and other governmental agencies and consumer groups established by the CPUC in D.02-08-071 and D.03-06-071. The existence of this Agreement is not subject to this confidentiality obligation; provided that neither Party shall make any public announcement relating to this Agreement unless required pursuant to subsection (i) or (vi) of the foregoing sentence of this Section 10.11. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in

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connection with, this confidentiality obligation. With respect to information provided in connection with a Transaction, this obligation shall survive for a period of three (3) years following the expiration or termination of such Transaction. With respect to information provided under this Agreement, this obligation shall survive for a period of three (3) years following the expiration or termination of this Agreement. For the purposes of this Section 10.11, “Affiliate” for Party A shall mean __________Chevron Corporation, Chevron U.S.A. Inc., Chevron Kern River Cogeneration Company, Western Sierra Energy Company and Edison Mission Energy and “Affiliate” for Party B shall mean Edison International; provided, however, that for Party A, "Affiliate" shall not apply to the power marketing or trading personnel of Chevron Corporation, Chevron U.S.A. Inc., Chevron Kern River Cogeneration Company, Western Sierra Energy Company or Edison Mission Energy.” New Sections 10.12 and 10.13 shall be added as follows: “10.12 No Agency. In performing their respective obligations hereunder, neither Party is acting, or is authorized to act, as agent of the other Party.” “10.13 Mobile Sierra Doctrine. (a) Absent the agreement of all Parties to the proposed change, the standard of review for changes to any rate, charge, classification, term or condition of this Agreement, whether proposed by a Party (to the extent that any waiver in subsection (b) below is unenforceable or ineffective as to such Party), a non-party or FERC acting sua sponte, shall be the ‘public interest’ standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the ‘Mobile Sierra’ doctrine). (b) Notwithstanding any provision of Agreement, and absent the prior written agreement of the Parties, each Party, to the fullest extent permitted by Applicable Laws, for itself and its respective successors and assigns, hereby also expressly and irrevocably waives any rights it can or may have, now or in the future, whether under Sections 205, 206, or 306 of the Federal Power Act or otherwise, to seek to obtain from FERC by any means, directly or indirectly (through complaint, investigation, supporting a third party seeking to obtain or otherwise), and each hereby covenants and agrees not at any time to seek to so obtain, an order from FERC changing any Section of this Agreement specifying any rate or other material economic terms and conditions agreed to by the Parties.” SCHEDULE P: PRODUCTS AND DEFINITIONS. Amend Schedule P as follows: The following definitions are added: “ ‘CAISO Energy’ means with respect to a Transaction, a Product under which the Seller shall sell and the Buyer shall purchase a quantity of energy equal to the hourly quantity without Ancillary Services (as defined in the Tariff) that is or will be scheduled as a schedule coordinator to schedule coordinator transaction pursuant to the applicable tariff and protocol provisions of the CAISO (as amended from time to time, the ‘Tariff’) for which the only excuse for failure to deliver or receive is an Uncontrollable Force (as defined in the Tariff).” The following products are added:

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“Other Products and Service Levels. If the Parties agree to a service level or product defined by a different agreement, set of rules, tariff, or protocol (herein, the ‘agreement’) (i.e., the WSPP Agreement) for a particular Transaction, then, unless the Parties expressly state and agree that all the terms and conditions of such other agreement will apply, such reference to a service level or product defined by such other agreement means that the service level or product for that Transaction is subject to the applicable regional independent system operator and/or utility reliability requirements and guidelines as well as the permitted excuses for performance, Force Majeure, Uncontrollable Forces, or other such excuses applicable to performance under such other agreement, to the extent inconsistent with the terms of this Agreement, provided, however, that all other terms and conditions of this Agreement shall and do remain applicable including, without limitation, Section 2.2; and provided, further that with respect to any Transaction for a product or service level defined by such other agreement, the methodology for calculating the payments for failure to deliver or receive shall be in accordance with Sections 4.1 and 4.2 of the Transition Master Agreement; provided, further that the ‘Accelerated Payment of Damages’ addressed in Article Four and agreed to in the Cover Sheet of the Transition Master Agreement shall continue to apply.” “Into __________ (the ‘Receiving Transmission Provider’), Seller’s Daily Choice” is deleted in its entirety.

IN WITNESS WHEREOF, the Parties have caused this Transition Master Agreement to be duly executed as of the date first above written. Party A: KERN RIVER COGENERATION COMPANY Party B: SOUTHERN CALIFORNIA EDISON COMPANY By:

By:

Name: Neil Burgess

Name: Marc L. Ulrich

Title:

Title:

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

DISCLAIMER: This Master Power Purchase and Sale Agreement was prepared by a committee of representatives of Edison Electric Institute (“EEI”) and National Energy Marketers Association (“NEM”) member companies to facilitate orderly trading in and development of wholesale power markets. Neither EEI nor NEM nor any member company nor any of their agents, representatives or attorneys shall be responsible for its use, or any damages resulting there from. By providing this Agreement EEI and NEM do not offer legal advice and all users are urged to consult their own legal counsel to ensure that their commercial objectives will be achieved and their legal interests are adequately protected.

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SCHEDULE 1 – Form of Letter of Credit ISSUE DATE: L/C NO.: __________________ ACCOUNT PARTY: ACCOUNT NAME ADDRESS CITY, STATE XXXXX-XXXX BENEFICIARY NAME ADDRESS CITY, STATE XXXXX-XXXX

AMOUNT: USD XXXX.00 (XXX AND 00/100 UNITED STATES DOLLARS)

WE HEREBY ESTABLISH THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT NO. ______________ FOR AN AGGREGATE AMOUNT NOT TO EXCEED THE AMOUNT INDICATED ABOVE, EXPIRING AT OUR COUNTERS WITH OUR CLOSE OF BUSINESS ON (DATE). THIS LETTER OF CREDIT IS AVAILABLE WITH (BANK NAME), AGAINST PRESENTATION OF YOUR DRAFT AT SIGHT DRAWN ON (BANK NAME), WHEN ACCOMPANIED BY:

1) THE ORIGINAL OF THIS LETTER OF CREDIT (OR A PHOTOCOPY OF THE ORIGINAL FOR PARTIAL DRAWINGS) AND ANY SUBSEQUENT AMENDMENTS, IF ANY; AND

2) A DRAW CERTIFICATE (SEE EXHIBIT A) PURPORTEDLY SIGNED BY ONE OF THE BENEFICIARY’S OFFICIALSREPRESENTATIVES. BENEFICIARY SHALL BE ENTITLED TO DRAW UPON THIS LETTER OF CREDIT UP TO THE STATED AMOUNT, IN ONE OR MORE DRAWINGS; PROVIDED HOWEVER, THAT IF ANY DRAWING WOULD EXCEED THE STATED AMOUNT, BENEFICIARY SHALL BE ENTITLED TO DRAW ONLY THAT PORTION THAT WOULD NOT EXCEED THE STATED AMOUNT. ALL CORRESPONDENCE AND ANY DRAWINGS HEREUNDER ARE TO BE DIRECTED TO (BANK ADDRESS/CONTACT). WE HEREBY AGREE WITH YOU THAT DRAFTS DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS AND CONDITIONS OF THIS LETTER OF CREDIT WILL BE DULY HONORED. THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT IS ISSUED SUBJECT TO THE INTERNATIONAL STANDBY PRACTICES 1998, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 590 (ISP98) AND AS TO MATTERS NOT ADDRESSED BY THE ISP98 THIS LETTER OF CREDIT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICT OF LAWS. THE NUMBER AND THE DATE OF OUR CREDIT AND THE NAME OF OUR BANK MUST BE QUOTED ON ALL DRAFTS REQUIRED.

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EXHIBIT A DRAW CERTIFICATE AN “EVENT OF DEFAULT” OR “EARLY TERMINATION DATE” (AS DEFINED IN SECTION 5 OF THE EDISON ELECTRIC INSTITUTE MASTER POWER PURCHASE & SALE AGREEMENT VERSION 2.1 AS MODIFIED ON 4/25/00 BETWEEN ACCOUNT PARTY AND BENEFICIARY, DATED _____________________ (THE “POWER PURCHASE AND SALE AGREEMENT”)) HAS OCCURRED AND IS CONTINUING WITH RESPECT TO THE ACCOUNT PARTY UNDER THIS LETTER OF CREDIT. WHEREFORE, THE UNDERSIGNED DOES HEREBY DEMAND PAYMENT TO THE UNDERSIGNED OF $USD (INSERT AMOUNT) BUT NOT TO EXCEED THE REMAINING UNDRAWN AMOUNT OF THE LETTER OF CREDIT. THE AMOUNT DEMANDED UNDER THIS LETTER OF CREDIT HAS BEEN COMPUTED IN ACCORDANCE WITH THE POWER PURCHASE AND SALE AGREEMENT. (COMPANY NAME)

By: (SIGNATURE OF COMPANY OFFICERREPRESENTATIVE) Title: _____________________________________

DATED: _________________________

24

Document comparison by Workshare Professional on Monday, December 10, 2012 9:16:11 AM Input: Document 1 ID Description

Document 2 ID

Description Rendering set

file://J:\RAP Contract Origination\2011 CHP\03_Issue Package\Attachment D-1 - EEI Master\Archive\Attachment D-1 - EEI Master Cover Sheet Elections.doc Attachment D-1 - EEI Master Cover Sheet Elections file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\Transition Contract Applications\2801 & 2058 - KRCC & Sycamore\Subsequent PPAs\Posting for Approval\20121012\KRCC Contract\20121012 KRCC Transition EEI.DOC 20121012 KRCC Transition EEI standard

Legend: Insertion Deletion Moved from Moved to Style change Format change Moved deletion Inserted cell Deleted cell Moved cell Split/Merged cell Padding cell Statistics: Count Insertions Deletions Moved from Moved to Style change Format changed

176 102 2 2 0 0

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282

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between [BUYER’S NAME] SOUTHERN CALIFORNIA EDISON COMPANY and [SELLER’S NAME] KERN RIVER COGENERATION COMPANY (RAP ID #[Number]2811)

Transition Standard Contract for Existing Qualifying Cogeneration Facilities

TERMS THAT ARE BOXED AND SHADED IN LIGHT YELLOW AND/OR BRACKETED AND IN BLUE FONT ARE EITHER BUYER COMMENTS OR GENERATING FACILITYTYPE SPECIFIC COMMENTS THAT SHOULD BE REMOVED, ACCEPTED OR COMPLETED, AS APPLICABLE.

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

TABLE OF CONTENTS LIST OF EXHIBITS ....................................................................................................... iiiiv  PREAMBLE ........................................................................................................................1  RECITALS ..........................................................................................................................1  ARTICLE ONE:  SPECIAL CONDITIONS ................................................................3  1.01  Term ................................................................................................................3  1.02  Generating Facility..........................................................................................3  1.03  Delivery Point .................................................................................................4  1.04  Capacity Performance Requirements ..............................................................5  1.05  Maintenance Outages; Major Overhaul ..........................................................5  1.06  Power Product Prices ......................................................................................5  1.07  [Intentionally omitted.] ...................................................................................6  1.08  Scheduling Coordinator Election ....................................................................6  ARTICLE TWO: SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION ......................................................7  2.01  Seller’s Satisfaction of Obligations before the Term Start Date.....................7  2.02  Termination Rights of the Parties ...................................................................8  2.03  Rights and Obligations Surviving Termination ..............................................9  2.04  CPUC Filing and Approval of this Agreement .............................................10  2.05  FERC Filing and Approval ...........................................................................10  2.06  Commencement of Term under Confirmations ............................................11  ARTICLE THREE:  SELLER’S OBLIGATIONS .....................................................1012  3.01  Conveyance of the Product; Retained Benefits ........................................1012  3.02  Resource Adequacy Rulings .....................................................................1113  3.03  Site Control ...............................................................................................1214  3.04  Permits ......................................................................................................1214  3.05  Transmission .............................................................................................1214  3.06  CAISO Relationship .................................................................................1315  3.07  Generating Facility Modifications ...........................................................1315  3.08  Metering ....................................................................................................1517  3.09  Telemetry System .....................................................................................1618  3.10  Provision of Information ...........................................................................1719  3.11  [Intentionally omitted.] .............................................................................1820  3.12  Fuel Supply ...............................................................................................1820  3.13  Demonstrations .........................................................................................1820  3.14  Operation and Record Keeping .................................................................1820  3.15  Power Product Curtailments at Transmission Provider’s or CAISO’s Request ......................................................................................................2022  3.16  Report of Lost Output ...............................................................................2123  3.17  FERC Qualifying Cogeneration Facility Status ........................................2224  3.18  Notice of Cessation or Termination of Service Agreements ....................2225  3.19  Buyer’s Access Rights ..............................................................................2325  3.20  Seller Financial Information .....................................................................2325 

Table of Contents

i

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

NERC Electric System Reliability Standards ...........................................2628  Allocation of Availability Incentive Payments and Non-Availability Charges .....................................................................................................2729  3.23  Seller’s Reporting Requirements .............................................................2730  ARTICLE FOUR:  BUYER’S OBLIGATIONS.......................................................2831  4.01  Obligation to Pay ......................................................................................2831  4.02  Payment Adjustments ...............................................................................2831  4.03  Payment Statement and Payment ..............................................................2932  4.04  GHG Compliance Costs............................................................................3135  4.05  No Representation by Buyer .....................................................................3135  4.06  Buyer’s Responsibility ..............................................................................3235  4.07  Buyer’s Reporting Requirements ..............................................................3235  ARTICLE FIVE:  FORCE MAJEURE ...................................................................3336  5.01  No Default for Force Majeure...................................................................3336  5.02  Requirements Applicable to the Claiming Party ......................................3336  5.03  Termination ...............................................................................................3336  ARTICLE SIX:  EVENTS OF DEFAULT; REMEDIES .....................................3437  6.01  Events of Default ......................................................................................3437  6.02  Early Termination .....................................................................................3740  6.03  Termination Payment ................................................................................3740  ARTICLE SEVEN:  LIMITATIONS OF LIABILITIES ............................................3842  ARTICLE EIGHT:  GOVERNMENTAL CHARGES...............................................4044  8.01  Cooperation to Minimize Tax Liabilities ..................................................4044  8.02  Governmental Charges..............................................................................4044  8.03  Providing Information to Taxing Governmental Authorities ...................4044  ARTICLE NINE:  MISCELLANEOUS ..................................................................4145  9.01  Representations and Warranties ................................................................4145  9.02  Additional Representations, Warranties, and Covenants by Seller ..........4246  9.03  Indemnity ..................................................................................................4246  9.04  Assignment ...............................................................................................4448  9.05  Consent to Collateral Assignment ............................................................4549  9.06  Governing Law and Jury Trial Waiver .....................................................4852  9.07  Notices ......................................................................................................4852  9.08  General ......................................................................................................4853  9.09  Confidentiality ..........................................................................................5054  9.10  Insurance ...................................................................................................5256  9.11  Nondedication ...........................................................................................5458  9.12  Mobile Sierra ............................................................................................5459  9.13  Seller Ownership and Control of Generating Facility ..............................5459  9.14  Simple Interest Payments ..........................................................................5559  9.15  Payments ...................................................................................................5559  9.16  Provisional Relief......................................................................................5559  ARTICLE TEN:  DISPUTE RESOLUTION .........................................................5661  3.21  3.22 

Table of Contents

ii

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

10.01  Dispute Resolution ....................................................................................5661  10.02  Mediation ..................................................................................................5661  10.03  Arbitration .................................................................................................5661  SIGNATURES...............................................................................................................5964  

Table of Contents

iii

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

LIST OF EXHIBITS A.

Definitions

B.

Generating Facility and Site Description

C.

[Intentionally omitted]

D.

Monthly Contract Payment Calculation

D-1.

Force Majeure Credit Value

D-2.

Transmission Curtailment Credit Value

E.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

F.

[Intentionally omitted]

G.

Scheduling Coordinator Services

H.

[Intentionally omitted]

I.

Seller’s Forecasting Submittal and Accuracy Requirements

J.

CAISO Charges

K.

Scheduling and Delivery Deviation Adjustments

L.

Physical Trade Settlement Amount

M.

SC Trade Settlement Amount

N.

Notice List

O.

[Intentionally omitted]

P.

[Intentionally omitted]

Q.

[Intentionally omitted]

R.

Outage Schedule Submittal Requirements

S.

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

T.

QF Efficiency Monitoring Program – Cogeneration Data Reporting Form

Table of Contents

iv

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between [BUYER’S NAME] SOUTHERN CALIFORNIA EDISON COMPANY and [SELLER’S NAME] KERN RIVER COGENERATION COMPANY (RAP ID# [Number] #2811) PREAMBLE This Power Purchase and Sale Agreement by and between [Buyer’s name]Southern California Edison Company, a California corporation (“Buyer”), and [Seller’s name], a [Seller’s form of business entity and state of registration]Kern River Cogeneration Company, a California general partnership (“Seller”), together with the exhibits, attachments, and any applicable referenced collateral agreement or similar arrangement between the Parties that is expressly incorporated into this Agreement by the Parties (collectively, this “Agreement”), is made, effective and binding as of [Date of execution]October 15, 2012 (the “Effective Date”). Buyer and Seller are sometimes referred to in this Agreement individually as a “Party” and jointly as the “Parties.” Unless the context otherwise specifies or requires, initially capitalized terms used in this Agreement have the meanings set forth in Exhibit A. RECITALS A.

On or about September 20, 2007, the CPUC issued Decision (“D.”) 07-09-040 (the “Decision”) which, among other things, directed Buyer to develop a form of a standard contract and offer such contract to qualifying facilities meeting the eligibility criteria set forth in the Decision.

B.

Commencing in May 2009, Pacific Gas and Electric Company, San Diego Gas and Electric Company, Southern California Edison Company, the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, the Independent Energy Producers Association, the Division of Ratepayer Advocates of the California Public Utilities Commission, and The Utility Reform Network (collectively, the “Settling Parties”) entered into CPUC-facilitated settlement

Preamble; Recitals

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

negotiations in order to resolve certain outstanding issues among the Settling Parties, including the implementation of the Decision. C.

Pursuant to the settlement negotiations, the Settling Parties entered into that certain Settlement Agreement, dated October 8, 2010 (the “Settlement Agreement”), which resolved certain issues pending in Rulemakings 99-11-022, 04-04-003, 04-04-025, and 06-02-013, and Application 08-11-001.

D.

The Settlement Agreement became effective on [___]November 23, 2011 (the “Settlement Effective Date”).

E.

Buyer is offering this Agreement to Seller in accordance with the requirements set forth in the Settlement Agreement, and Seller desires to enter into such Agreement.

G.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition EEI Agreement, including the Transition Tolling Confirmation and the Transition RA Confirmation.

H.

Pursuant to the terms and conditions set forth in the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation, Buyer will purchase from Seller and Seller will sell to Buyer the Product (as such term, in this instance only for purposes of this Agreement, is defined in each of the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation).

The Parties, intending to be legally bound, agree as follows:

Preamble; Recitals

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

ARTICLE ONE. 1.01

SPECIAL CONDITIONS

Term. The term of this Agreement (the “Term”) commences on [Date] (the “Term Start Date”)the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained (the “Term Start Date”); provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Term shall not commence until all of the condition precedents set forth in each of the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Term Start Date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03)), and ends [Date]June 30, 2015 (the “Term End Date”). The Term Start Date must occur on the first day following the termination of [insert title and date of the existing power purchase agreement between Buyer and Seller, including any amendments, as well as any extension agreementsAmended and Restated Parallel Generation Agreement between Kern River Cogeneration Company and Southern California Edison Company dated December 15, 2005, as amended by Amendment No. 1 dated May 30, 2006, and extended by letter agreement entered into pursuant D.07-09040] dated June 28, 2012 (the “Existing PPA”). {Buyer Comment: Seller designates the Term Start Date and the Term End Date; provided, however, that the Term must end on or before July 1, 2015. This Agreement may only be entered into with the California investor-owned utility with which Seller has an existing power purchase agreement (or an extension thereof as ordered by the CPUC in D.07-09-040).}

1.02

Generating Facility. (a)

Name; Designation. The name of the Generating Facility is [Generating Facility name]Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation is Kern River Cogeneration Company, which is an Existing Qualifying Cogeneration Facility.

(b)

Location; Site. The Generating Facility is located at [Generating Facility address],SW China Grade Loop, Bakersfield, CA 93308, and is further described in Exhibit B.

(c)

Qualifying Cogeneration Facility Type. As of the Effective Date, the Generating Facility, which includes the Generating Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation, is a [“topping-cycle cogeneration facility”, as defined in 18 CFR Part 292, Section

Article One

Special Conditions

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

292.202(d)] [“bottoming-cycle cogeneration facility”, as defined in 18 CFR Part 292, Section 292.202(e)]. (d)

Contract Capacity. As set forth in the following table, Seller may elect (i) only Firm Contract Capacity, (ii) only As-Available Contract Capacity, or (iii) both Firm Contract Capacity and As-Available Contract Capacity: Month January February March April May June July August September October November December

Monthly Firm Contract Capacity (kW) [___]150,000 [___]150,000 [___]149,000 [___]145,000 [___]142,000 [___]141,000 [___]140,000 [___]141,000 [___]142,000 [___]144,000 [___]146,000 [___]148,000

As-Available Contract Capacity (kW/) [___]4,000 [___]4,000 [___]5,000 [___]9,000 [___]12,000 [___]13,000 [___]14,000 [___]13,000 [___]12,000 [___]10,000 [___]8,000 [___]6,000

Net Contract Capacity (kW) [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000 [___]154,000

{Buyer Comment: The Net Contract Capacity must equal the sum of Firm Contract Capacity and As-Available Contract Capacity, and cannot exceed PMax.} Firm

Contract Capacity, As-Available Contract Capacity and Net Contract Capacity are subject to adjustment in accordance with Section 3.07(c). Subject to adjustment in accordance with Section 3.07(c), the Firm Contract Capacity for all months of the year must be less than or equal to [___]150,000 kW, and the As-Available Contract Capacity for all months of the year must be less than or equal to [___] kW.{Buyer Comment: Insert the amount of firm capacity and/or as-available capacity, as applicable, historically made available to Buyer by Seller under the Parties’ existing power purchase agreement (or an extension thereof as ordered by the CPUC in D.07-09-040).} 14,000 kW, and the sum of Firm Contract

Capacity and As-Available Contract Capacity for all months of the year must be less than or equal to 154,000 kW. (e)

Expected Term Year Energy Production. (i)

The Expected Term Year Energy Production for each Term Year equals [___]1,280,000,000 kWh.

{Buyer Comment: Expected Term Year Energy Production cannot exceed Net Contract Capacity at 100% capacity factor applied over the Term Year.}

Article One

Special Conditions

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(ii)

The Expected Term Year Energy Production may be revised in accordance with Section 3.07(c), or based on changes in the Site Host Load or the Site Host thermal requirements; provided, however, that such revision must be supported by a certification from a California-licensed professional engineer qualified to make a representation affirming that such revision is reasonable and based on (i) actual modifications to the Generating Facility performed or to be performed by Seller in accordance with and subject to Section 3.07(c), or (ii) changes in the Site Host Load or the Site Host thermal requirements. Such certification must include all data relied on to support the revised Expected Term Year Energy Production.

(iii)

Subject to adjustments in accordance with Section 1.02(e)(ii), the Expected Term Year Energy Production may never exceed [___]1,280,000,000 kWh in any Term Year.

{Buyer Comment: Insert the amount of electric energy historically delivered to Buyer by Seller under the Parties’ existing power purchase agreement (or an extension thereof as ordered by the CPUC in D.07-09-040)}.

1.03

Delivery Point. The delivery point is the point of delivery of the Power Product to the CAISO Controlled Grid which shall be between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal Magunden 230 kV line (the “Delivery Point”). Seller shall provide and convey to Buyer the Power Product from the Generating Facility at the Delivery Point. Title to and risk of loss related to the Power Product transfer from Seller to Buyer at the Delivery Point.

1.04

Capacity Performance Requirements. As further described in Exhibit D, if the Generating Facility elects to provide Firm Contract Capacity, then the Generating Facility must have a minimum Firm Contract Capacity performance requirement of 95% to earn the Maximum Firm Capacity Payment and a minimum Capacity Performance Requirement of 60% to earn any portion of the Maximum Firm Capacity Payment.

1.05

Maintenance Outages; Major Overhaul.

Article One

Special Conditions

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

1.06

(a)

The total Maintenance Debit Value for Maintenance Outages, as determined in accordance with Exhibit E, may not exceed 550 hours in the first Term Year. At the end of each Term Year following the first Term Year, up to a maximum of 50 unused hours may be carried over to the following Term Year. For each of the Term Years after the first Term Year, the total Maintenance Debit Value for Maintenance Outages may not exceed 550 hours plus hours carried over from prior Term Years; provided, however, that such Maintenance Debit Value may not exceed 600 hours in any Term Year.

(b)

Seller may (i) request one Major Overhaul Allowance (in accordance with Exhibit E) of up to 750 total hours, (ii) schedule no more than one Major Overhaul; provided, however, that the Maintenance Debit Value for such Major Overhaul may not exceed 750 hours.

(c)

If Seller utilizes all of its Major Overhaul Allowance during a Major Overhaul, the remaining portion of the Major Overhaul may be converted to a Maintenance Outage as far as Maintenance Credit Value and Maintenance Debit Value are concerned; provided, however, that Seller submits a Notice to Buyer of such conversion within 60 days of the end of such Major Overhaul.

(d)

During the Peak Months, Seller may only schedule Maintenance Outages during the non-peak hours of such Peak Months, and the monthly Maintenance Debit Value for Maintenance Outages during the Peak Months may not exceed 12 non-peak hours per Peak Month. Such limitation is part of, and not in addition to, the annual limits as set forth in Section 1.05(a).

Power Product Prices. (a)

Firm Capacity Price. The Firm Capacity Price equals $91.97 per kW-year.

(b)

As-Available Capacity Price. The As-Available Capacity Price is set forth in Section 3 of Exhibit D.

(c)

TOD Period Energy Price. The TOD Period Energy Price is set forth in Section 2 of Exhibit D.

1.07

[Intentionally omitted.]

1.08

Scheduling Coordinator Election. [Buyer][Seller][_________, an agent of Seller] is the Scheduling Coordinator under this Agreement. Notwithstanding anything to the contrary set forth in this Agreement, Buyer must be the Scheduling Coordinator under this Agreement if Seller intends to utilize the exemptions set forth in, and subject to, Sections 3.06(b) or 3.09(b). *** End of Article One ***

Article One

Special Conditions

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

ARTICLE TWO.

2.01

SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION; CPUC AND FERC APPROVAL

Seller’s Satisfaction of Obligations before the Term Start Date. Seller shall satisfy each of the following obligations before the Term Start Date: (a)

The Generating Facility is a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(b)

Seller enters into all agreements, obtains all Governmental Authority approvals and Permits, and takes all steps necessary for it to: (i)

Operate the Generating Facility;

(ii)

Deliver electric energy from the Generating Facility to the Delivery Point; and

(iii)

Schedule, or arrange for a third party or Buyer to Schedule, the electric energy produced by the Generating Facility with the CAISO;

(c)

Seller’s Scheduling Coordinator, as set forth in Section 1.08, is authorized by the CAISO to Schedule the electric energy produced by the Generating Facility with the CAISO;

(d)

Seller satisfies its obligation to install the CAISO-Approved Meters, as set forth in this Agreement;

(e)

Seller furnishes to Buyer the insurance documents required under Section 9.10(c);

(f)

Seller is in compliance with the CAISO Tariff as set forth in this Agreement;

(g)

Seller enters into and fulfills all of its obligations under (i) the applicable interconnection agreements with the applicable Transmission Provider that are required to enable Parallel Operation of the Generating Facility with the interconnected electric system and the CAISO Controlled Grid, and (ii) any transmission, distribution or other service agreement that are required to enable Seller to transmit electric energy from the Generating Facility to the Delivery Point;

(h)

Seller furnishes to Buyer the documents required under Section 3.05; and

(i)

If Buyer is Scheduling Coordinator and the Generating Facility is PIRP-eligible, then the Generating Facility is certified as a PIRP resource by the CAISO.

Article Two

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

2.02

Termination Rights of the Parties. (a)

[Intentionally omitted.]

(b)

Termination Right of Seller.

(c)

Article Two

(i)

Seller has the right to terminate this Agreement if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected by Buyer in a competitive solicitation. In such an instance, the termination of this Agreement will be effective as of midnight the day before the commencement of any delivery period for any electric energy, capacity or attributes from the Generating Facility which is selected by Buyer in such competitive solicitation.

(ii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected in a competitive solicitation by a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 2.02(b)(ii) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

(iii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility jointly enter into an agreement for the sale of electric energy, capacity or attributes with a California investorowned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 2.02(b)(iii) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

Event of Default. In the event of an uncured Event of Default or an Event of Default for which there is no opportunity for cure permitted in this Agreement,

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

the Non-Defaulting Party may, at its option, terminate this Agreement as set forth in Section 6.02 and, if the Non-Defaulting Party is Buyer, then Seller (or any entity over which Seller or any owner or manager of Seller exercises control) agrees to waive any right it may have to enter into any new mandatory mustpurchase contract (including the Transition PPA, the QF PPA, or the Optional AsAvailable PPA, as such terms are defined in the Settlement Agreement) to sell electric energy, capacity or Related Products from the Generating Facility to Buyer or any other California investor-owned utility for a period of 365 days following the date of such termination. For purposes of this Section 2.02(c), “control” means the direct or indirect ownership of 20% or more of the outstanding capital stock or other equity interests having ordinary voting power.

2.03

(d)

End of Term. This Agreement automatically terminates at 11:59 p.m. PPT on the Term End Date.

(e)

Failure to Obtain CPUC Approval or FERC Approval. If CPUC Approval or FERC Approval has not been obtained by the Term End Date, this Agreement shall terminate in accordance with Section 2.02(d).

(f)

Termination of the Transition EEI Agreement. If the Transition EEI Agreement is terminated before the commencement of the Delivery Period of either the Transition Tolling Confirmation or the Transition RA Confirmation (as defined therein), then this Agreement will automatically terminate, without liability for a Forward Settlement Amount by either Party, on the date of the termination of the Transition EEI Agreement.

Rights and Obligations Surviving Termination. The rights and obligations of the Parties that are intended to survive a termination of this Agreement are all such rights and obligations that this Agreement expressly provides survive such termination as well as those rights and obligations arising from either Parties’ covenants, agreements, representations or warranties applicable to, or to be performed, at, before or as a result of the termination of this Agreement, including: (a)

The obligation of Buyer to make all outstanding Monthly Contract Payments for periods before termination of this Agreement;

(b)

The obligation of Buyer to invoice Seller for all payment adjustments for periods before termination of this Agreement, as set forth in Section 4.02;

(c)

The obligation of Seller to pay any Buyer payment-adjustment invoice described in Section 4.03(b) for periods before termination of this Agreement within 30 days of Seller’s receipt of such invoice;

Article Two

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

2.04

2.05

(d)

The obligation of Buyer or Seller, as applicable, to make payments, if any, after the termination of this Agreement, as set forth in Section 3(c) of Exhibit S;

(e)

The obligation to make a Termination Payment, as set forth in Section 6.03;

(f)

The indemnity obligations, as set forth in Section 9.03;

(g)

The obligation of confidentiality, as set forth in Section 9.09;

(h)

The right to pursue remedies under Section 6.02(c); and

(i)

The limitation of damages under Article Seven.

CPUC Filing and Approval of this Agreement. (a)

Within 60 days after the Effective Date, Buyer shall file with the CPUC the appropriate request for CPUC Approval. Buyer shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support Buyer in obtaining CPUC Approval. Buyer has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Before the Term Start Date, Buyer must have obtained or waived CPUC Approval.

FERC Filing and Approval. (a)

Article Two

Within 60 days of the Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent Seller’s Satisfaction of Obligations before the Term Start Date; Termination

Page 10

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

evaluator report with respect to the transactions contemplated hereby within 50 days after the Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Buyer provides Seller such independent evaluator report. (b)

2.06

Notwithstanding Seller’s and Buyer’s execution and delivery of this Agreement, this Agreement is subject to FERC Approval and the Term Start Date shall not occur until FERC Approval has been obtained.

Commencement of Term under Confirmations. Notwithstanding anything to the contrary set forth in this Agreement, the Term of this Agreement will not commence until the commencement of the Delivery Period of the Transition Tolling Confirmation and the Transition RA Confirmation (as defined respectively therein). *** End of Article Two ***

Article Two

Seller’s Satisfaction of Obligations before the Term Start Date; Termination

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

ARTICLE THREE. SELLER’S OBLIGATIONS 3.01

Conveyance of the Product; Retained Benefits. (a)

Product. During the Term, Seller shall provide and convey the Product to Buyer in accordance with the terms of this Agreement, and Buyer shall have the exclusive right to the Product and all benefits derived therefrom, including the exclusive right to sell, convey, transfer, allocate, designate, award, report or otherwise provide any and all of the Product purchased under this Agreement and the right to all revenues generated from the use, sale or marketing of the Product.

(b)

Green Attributes. Seller hereby provides and conveys all Green Attributes associated with the Related Products as part of the Product being delivered during the Term. Seller represents and warrants that Seller holds the rights to all Green Attributes associated with the Related Products, and Seller agrees to convey and hereby conveys all such Green Attributes to Buyer as included in the delivery of the Product from the Project.

(c)

Further Action by Seller. Seller shall, at its own cost, take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term, which actions may include: (i)

Cooperating with the Governmental Authority responsible for resource adequacy administration to certify the Generating Facility for resource adequacy purposes;

(ii)

Testing the Generating Facility as may be required to certify the Generating Facility for resource adequacy purposes in accordance with the requirements set forth in the CAISO Tariff or as otherwise agreed to by the Parties;

(iii)

Committing to Buyer the Net Contract Capacity; and

(iv)

Complying with Applicable Laws regarding the registration, transfer or ownership of Green Attributes associated with the Related Products, including, if applicable to the Generating Facility, participation in WREGIS or other process recognized under Applicable Laws. With respect to WREGIS, at Buyer’s option, Seller shall cause and allow Buyer to be the “Qualified Reporting Entity” and “Account Holder” (as these two terms are defined by WREGIS) for the Generating Facility;

Article Three

Seller’s Obligations

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(d)

3.02

(v)

Complying with all CAISO Tariff requirements applicable to a Resource Adequacy Resource; and

(vi)

If Buyer is not the Scheduling Coordinator: 1)

Timely submitting, or causing Seller’s Scheduling Coordinator to timely submit, Supply Plans to identify and confirm the Net Qualifying Capacity of the Generating Facility sold to Buyer as a Resource Adequacy Resource; and

2)

Causing the Generating Facility’s Scheduling Coordinator to certify to Buyer, within 15 Business Days before the relevant deadline for any applicable RAR Showing or LAR Showing, that Buyer will be credited with the Net Qualifying Capacity of the Generating Facility for such RAR Showing or LAR Showing in the Generating Facility’s Scheduling Coordinator’s Supply Plan.

Retained Benefits. Seller shall retain for its own use or disposition all Financial Incentives and all attributes, benefits and credits associated with the Generating Facility and the electrical or thermal energy produced therefrom, other than the Power Product and the Related Products. Subject to Seller’s compliance with the applicable FERC rules and regulations, Seller may use, provide and convey any electric energy, capacity, Green Attributes, Capacity Attributes, Resource Adequacy Benefits, or any other product or benefit associated with the Generating Facility or the output thereof before the Term Start Date.

Resource Adequacy Rulings. During the Term, Seller shall grant, pledge, assign and otherwise commit to Buyer the generating capacity of the Generating Facility associated with the Related Products in order for Buyer to use in meeting its resource adequacy obligations under any Resource Adequacy Ruling. Seller: (a)

Has not used, granted, pledged, assigned or otherwise committed any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer for any portion of the Term;

(b)

Will not during the Term use, grant, pledge, assign or otherwise commit any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer; and

(c)

Shall take all reasonable actions (including complying with all current and future CAISO Tariff provisions and decisions of the CPUC or any other Governmental

Article Three

Seller’s Obligations

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Authority that address Resource Adequacy Rulings) and execute all documents that are reasonable and necessary to effect the use of the generating capacity of the Generating Facility associated with the Related Products for Buyer’s sole benefit throughout the Term. 3.03

Site Control. Seller shall have Site Control as of the earlier of: (a) the Term Start Date and (b) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term. Seller shall provide Buyer with prompt Notice of any change in the status of Seller’s Site Control.

3.04

Permits. Seller shall obtain and maintain any and all Permits necessary for the Operation of the Generating Facility and to deliver electric energy from the Generating Facility to the Delivery Point.

3.05

Transmission. (a)

Interconnection Studies. Seller has provided Buyer with true and complete copies of all Interconnection Studies received by Seller for the Generating Facility after the date that is 24 months before the Effective Date.

(b)

Seller’s Responsibility. Seller shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable Parallel Operation of the Generating Facility with the Transmission Provider’s electric system and the applicable Control Area operator’s electric grid and to effect Scheduling of the electric energy from the Generating Facility and transmission and delivery to the Delivery Point. Except as otherwise provided in its interconnection agreement, the CAISO Tariff, or the Transmission Provider’s tariff, rules or regulations, Seller shall pay all Transmission Provider charges or other charges directly caused by, associated with, or allocated to the following: (i)

All required Interconnection Studies, facilities upgrades, and agreements;

(ii)

Interconnection of the Generating Facility to the Transmission Provider’s electric system;

(iii)

Any costs or fees associated with obtaining and maintaining a wholesale distribution access tariff agreement, if applicable; and

(iv)

The transmission and delivery of electric energy from the Generating Facility to the Delivery Point.

Article Three

Seller’s Obligations

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(c)

3.06

3.07

Acknowledgement. The Parties acknowledge and agree that any other agreement between Seller and Buyer, including any interconnection agreements, is separate and apart from this Agreement and does not modify or add to the Parties’ obligations under this Agreement, and that any Party’s breach under such other agreement does not excuse such Party’s nonperformance under this Agreement, except to the extent that such breach constitutes a Force Majeure under this Agreement.

CAISO Relationship. (a)

Throughout the Term, Seller shall comply with all applicable provisions of the CAISO Tariff (including complying with any exemption obtained from the CAISO pursuant to the CAISO Tariff), as determined by the CAISO, including securing and maintaining in full force all of the CAISO agreements, certifications and approvals required in order for the Generating Facility to comply with the applicable provisions of the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.06(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not installed one or more CAISO-Approved Meters for the Generating Facility on or before the Term Start Date, Seller will not be in breach of this Agreement with respect to such requirement to install CAISOApproved Meter(s) if Seller installs such CAISO-Approved Meter(s) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement to install CAISO-Approved Meter(s) by complying with a milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to Seller’s requirement that the CAISO-Approved Meters for the Generating Facility be installed on or before the Term Start Date, which extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request.

(c)

Buyer agrees that, subject to the limitation set forth in Section 3.06(b) and upon the CAISO’s request, pending the installation of the CAISO-Approved Meter(s) by Seller for the Generating Facility, Buyer shall provide to the CAISO any settlement quality meter data reasonably requested by the CAISO for settlement purposes.

Generating Facility Modifications.

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(a)

Seller is responsible for the design, procurement and construction of all modifications necessary for the Generating Facility to meet the requirements of this Agreement and to comply with any restriction set forth in any Permit.

(b)

Seller shall provide 30 days advance Notice to Buyer if there is any modification (other than a routine fluctuation in output or consumption) of the Generating Facility, the Site Host Load or operations related to the Site Host Load changing:

(c)

(i)

Electric energy output by five percent of Expected Term Year Energy Production; or

(ii)

The type of Primary Fuel consumed by the Generating Facility.

Seller may not materially modify or repower the Generating Facility without prior written consent of Buyer; provided, however, that modifications or repowering will not be deemed material and is permitted under this Agreement without further consideration, other than Notices required under Section 3.07(b), if: (i)

Capacity added as a result of such modification or repower (including the addition of a steam turbine) over the Term is within the applicable MW limits set forth in the following table (for a Generating Facility with multiple turbines, the limits below are limits per turbine): Current Turbine Name Plate on the Effective Date

Increase to Turbine Name Plate Over the Term

10MW or Less

5MW

Greater than 10MW but less than 20MW

10MW

Greater than or equal to 20MW but less than 25MW

15MW

Greater than or equal to 25MW but less than 50MW

20MW

Greater than or equal to 50MW but less than 100MW

25MW

Greater than or equal to 100 but less than 200MW

35MW

Greater than or equal to 200 but less than 350MW

45MW

Greater than or equal 350MW

50MW

Or, (ii)

Such modification or repower is reasonably necessary to respond to a Force Majeure or a change in law or regulation, and a qualified Californialicensed professional engineer verifies that such modification or repower is not oversized relative to other equipment on the market. Seller shall

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bear the cost of such professional engineer and Seller shall secure all studies and upgrades necessitated by or associated with such modification or repower.

3.08

(d)

Seller acknowledges that nothing in this Section 3.07 excuses Seller from any requirements of the CAISO’s interconnection process or any other applicable interconnection process.

(e)

Seller is solely responsible for all GHG Compliance Costs and all other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating Facility to the extent that such GHG Compliance Costs or other costs result from Seller’s modification or repowering of the Generating Facility in accordance with this Section 3.07.

Metering. (a)

CAISO-Approved Meter. Seller shall, at its own cost, install, maintain and test all CAISO-Approved Meters pursuant to the CAISO Tariff or other applicable metering requirements.

(b)

Check Meter. Buyer may, at its sole cost, furnish and install one Check Meter at the interconnection associated with the Generating Facility at a location designated by Seller or any other location mutually agreeable to the Parties. The Check Meter location must allow for the Check Meter to be interconnected with Buyer’s communication network to permit: (i)

Periodic, remote collection of revenue quality meter data; and

(ii)

Back-up real time transmission of operating-quality meter data through the Telemetry System set forth in Section 3.09; provided, however, that the transmission of such meter data through the Telemetry System is permitted by the CAISO.

Buyer shall test and recalibrate the Check Meter at least once every Term Year. The Check Meter will be locked or sealed, and the lock or seal shall be broken only by a Buyer representative. Seller has the right to be present whenever such lock or seal is broken. Buyer shall replace the Check Meter battery at least once every 36 months; provided, however, if the Check Meter battery fails, Buyer shall promptly replace such battery. (c)

Use of Check Meter for Back-Up Purposes. (i)

Buyer shall routinely compare the Check Meter data to the CAISOApproved Meter data.

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3.09

(ii)

If the deviation between the CAISO-Approved Meter data (after adjusting (1) for all appropriate compensation and correction factors applied, if applicable, by the CAISO to the CAISO-Approved Meter, or (2) for any deviation that may result due to the CAISO-Approved Meter and Check Meter being physically situated in different locations) and the Check Meter data for any comparison is greater than 0.3%, Buyer shall provide Notice to Seller of such deviation and the Parties shall mutually arrange for a meter check or recertification of the Check Meter or CAISOApproved Meter, as applicable.

(iii)

Each Party shall bear its own costs for any meter check or recertification.

(iv)

Testing procedures and standards for the Check Meter will be the same as for a comparable Buyer-owned meter. Seller shall have the right to have representatives present during all such tests.

(v)

The Check Meter is intended to be used (1) for back-up purposes in the event of a failure or other malfunction of the CAISO-Approved Meter, and (2) in the event Seller has not installed the CAISO-Approved Meter, as further described in Section 3.06(b). Data from the Check Meter will only be used to validate the CAISO-Approved Meter data and, in the event of a failure or other malfunction of the CAISO-Approved Meter, or in accordance with and subject to Section 3.06(b), in place of the CAISOApproved Meter until such time that the CAISO-Approved Meter is certified.

Telemetry System. (a)

Seller is responsible for designing, furnishing, installing, maintaining and testing a real time Telemetry System in accordance with the CAISO Tariff provisions applicable to the Generating Facility. Seller has the right to request any exemption from such requirements from the CAISO so long as it is obtained pursuant to the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.09(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not complied with Section 3.09(a) on or before the Term Start Date, Seller will not be in breach of this Agreement if Seller fully complies with Section 3.09(a) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement set forth in Section 3.09(a) by complying with a

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milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to the requirement set forth in Section 3.09(a), which extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request. (c)

3.10

Buyer agrees that, subject to the limitation set forth in Section 3.09(b) and upon the CAISO’s request, pending Seller compliance with Section 3.09(a), Buyer shall provide to the CAISO any telemetry data reasonably requested by the CAISO for operating information purposes.

Provision of Information. (a)

Within 30 days after the Effective Date, Seller shall provide to Buyer (to the extent not already in Buyer’s possession), subject to Section 9.09: (i)

All currently operative agreements with providers of distribution, transmission or interconnection services for the Generating Facility and all amendments thereto;

(ii)

Any currently operative filings at FERC, including any rulings, orders or other pleadings or papers filed by FERC, concerning the qualification of the Generating Facility as a Qualifying Cogeneration Facility;

(iii)

Any Permits reasonably requested by Buyer concerning the Operation or licensing of the Generating Facility, and any applications or filings requesting or pertaining to such Permits;

(iv)

Each of the following engineering documents for the Generating Facility: 1)

Site plan drawings;

2)

Electrical one-line diagrams;

3)

Control and data acquisition details and configuration documents;

4)

Major electrical equipment specifications;

5)

Process flow diagrams;

6)

Piping and instrumentation diagrams;

7)

General arrangement drawings; and

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8) (v)

Aerial photographs of the Site, if any; and

Instrument specifications, installation instructions, operating manuals, maintenance procedures and wiring diagrams for the CAISO-Approved Meter(s) and the Telemetry System reasonably requested by Buyer.

(b)

If applicable and subject to Section 9.09, as soon as possible, Seller shall provide to Buyer (i) engineering specifications and design drawings for the Telemetry System, and (ii) annual test reports for the CAISO-Approved Meters.

(c)

Subject to Section 9.09 and upon Buyer’s request, Seller shall make commercially reasonable efforts to provide Buyer with all documentation necessary for Buyer to comply with any discovery or data request for information from the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, which commercially reasonable efforts shall, at a minimum, include providing Buyer with all documentation regarding the operational characteristics or past performance of the Generating Facility if such documentation is requested by the CPUC.

3.11

[Intentionally omitted.]

3.12

Fuel Supply. Seller shall supply all fuel required for the Power Product and any testing or demonstration of the Generating Facility.

3.13

Demonstrations. Seller shall comply with any demonstration required for Resource Adequacy Rulings; provided, however, if such demonstrations could interfere with the operations of Seller, Seller shall be entitled to challenge such requirements with the CPUC or other relevant agency. Absent a ruling or other action granting a stay, compliance shall be required pending resolution of the challenge.

3.14

Operation and Record Keeping. Seller shall: (a)

Operate the Generating Facility in accordance with Prudent Electrical Practices;

(b)

Comply with the Forecasting requirements, as set forth in Exhibit I;

(c)

Use reasonable efforts to Operate the Generating Facility so that the Power Product conforms with the Forecast provided in accordance with Exhibit I;

(d)

Pay all CAISO Charges, as set forth in Exhibit J;

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(e)

Pay all SDD Adjustments for which Seller is responsible, as set forth in Exhibit K;

(f)

Comply with the Maintenance Outage scheduling procedures, as set forth in Exhibit E;

(g)

Comply with the Outage Schedule Submittal Requirements, as set forth in Exhibit R;

(h)

Use reasonable efforts to deliver the maximum possible quantity of As-Available Contract Capacity and associated electric energy during an Emergency Condition or a System Emergency;

(i)

Use reasonable efforts to reschedule any outage that occurs during an Emergency Condition or a System Emergency;

(j)

Keep a daily Operating log for the Generating Facility that includes information on availability, outages, circuit breaker trip operations requiring a manual reset, and any significant events related to the Operation of the Generating Facility, including: (i)

Real and reactive power production;

(ii)

Changes in Operating status;

(iii)

Protective apparatus operations; and

(iv)

Any unusual conditions found during inspections;

(k)

Keep all Operating records required of a Qualifying Cogeneration Facility by any applicable CPUC order as well as any additional information that may be required of a Qualifying Cogeneration Facility in order to demonstrate compliance with all applicable California utility industry standards which have been adopted by the CPUC;

(l)

Provide copies of all daily Operating logs and Operating records to Buyer within 20 days of a Notice from Buyer;

(m)

Provide, upon Buyer’s request, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code or any Applicable Law mandating the reporting by investor-owned utilities of expected or experienced outages by facilities under contract to supply electric energy;

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3.15

(n)

Pay all Scheduling Fees, as set forth in Exhibit G;

(o)

[Intentionally omitted]

(p)

Register with the NERC as the Generating Facility’s Generator Owner and Generator Operator if Seller is required to register by the NERC;

(q)

Maintain documentation of all procedures applicable to the testing and maintenance of the Generating Facility protective devices as necessary to comply with the NERC Reliability Standards applicable to protection systems for electric generators if Seller is required to maintain such documentation by the NERC;

(r)

If Buyer is Scheduling Coordinator, then at least 30 days before the Term End Date, or in accordance with Section 7(a) of Exhibit G, or as soon as practicable before the date of an early termination of this Agreement, (i) submit to the CAISO the name of the Scheduling Coordinator that will replace Buyer, and (ii) cause the Scheduling Coordinator that will replace Buyer to submit a letter to the CAISO accepting the designation as Seller’s Scheduling Coordinator; and

(s)

If Buyer is not Scheduling Coordinator: (i)

Cause its Scheduling Coordinator to submit a Self-Schedule of Seller’s Day-Ahead Forecast associated with the Generating Facility through the IFM; Seller shall then submit the quantity associated with the SelfSchedule of Seller’s Day-Ahead Forecast as a Physical Trade to Buyer in the IFM, specifying the generating resource identifier and all other CAISO-required Inter-SC Trade attributes;

(ii)

Cause its Scheduling Coordinator to submit the IFM Day-Ahead Schedule quantity associated with the Generating Facility as an Inter-SC Trade of IFM Load Uplift Obligation to Buyer to be cleared through the Real-Time Market, specifying all CAISO-required Inter-SC Trade attributes; and

(iii)

Make available to Buyer all CAISO settlement data with respect to the Generating Facility required to validate payments made under this Agreement.

Power Product Curtailments at Transmission Provider’s or CAISO’s Request. (a)

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the CAISO, which may be communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when the CAISO orders curtailment and the Scheduling Coordinator

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implements such curtailment in compliance with the CAISO Tariff or applicable orders to avoid or address a declared System Emergency. (b)

(c)

3.16

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the Transmission Provider, which may be communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when curtailment of the Power Product is required to comply with: (i)

A CAISO curtailment declared pursuant to Section 3.15(a) or Transmission Provider declared Emergency Condition, subject to the interconnection agreement between Seller and the Transmission Provider; or

(ii)

Transmission Provider’s maintenance requirements, subject to the interconnection agreement between Seller and the Transmission Provider.

Notwithstanding the above, except as may be required in order to respond to any Emergency Condition or System Emergency, Buyer shall, consistent with FERC Order 888 and the interconnection agreement between Seller and the Transmission Provider and with the applicable provisions of the CAISO Tariff: (i)

Use reasonable good faith efforts to coordinate Transmission Provider’s curtailment needs with Seller to the extent it can influence such needs; or

(ii)

Request the Transmission Provider and CAISO limit the curtailment duration.

(d)

If Seller has entered into a QF PGA or PGA with the CAISO, or an interconnection agreement, the terms of the applicable QF PGA or PGA and the applicable interconnection agreement with respect to CAISO or Transmission Provider curtailments, shall govern the rights and obligations of Buyer and Seller to the extent any provision of this Section 3.15 is inconsistent with such applicable QF PGA or PGA, and interconnection agreement.

(e)

In the event Seller interconnects with a Person other than the CAISO, Seller shall adhere to any reliability curtailment order by such Person pursuant to the applicable tariff provisions of such Person.

Report of Lost Output. To the extent the conditions set forth in Sections 3.16(a) through (e) occur, Seller shall prepare and provide to Buyer, by the fifth Business Day following the end of each month during the Term, a lost output report. The lost output report shall

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identify the date, time, duration, cause and amount by which the Metered Energy was reduced below the Seller’s Energy Forecast due to:

3.17

(a)

Maintenance Outages;

(b)

Major Overhauls;

(c)

CAISO or Transmission Provider-ordered curtailments;

(d)

Force Majeure; or

(e)

Forced Outages.

FERC Qualifying Cogeneration Facility Status. (a)

(b)

Subject to Section 9.09, within 30 Business Days following the end of each year, and within 30 Business Days following the Term End Date, Seller shall provide to Buyer: (i)

A completed copy of Buyer’s “QF Efficiency Monitoring Program – Cogeneration Data Reporting Form”, substantially in the form of Exhibit T, with calculations and verifiable supporting data, which demonstrates the compliance of the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation with qualifying cogeneration facility operating and efficiency standards set forth in 18 CFR Part 292, Section 292.205 “Criteria for Qualifying Cogeneration Facilities”, for the applicable year; andor

(ii)

A copy of a FERC order waiving for the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation the applicable operating and efficiency standards for qualifying cogeneration facilities, as contemplated in 18 CFR Part 292, Section 292.205, “Criteria for Qualifying Cogeneration Facilities”, for the applicable year, if Seller has received such FERC order; provided, that in the event that Seller receives such a FERC order after the time periods set forth above, Seller shall satisfy this requirement by submitting such FERC order to Buyer within 5 Business Days after FERC’s issuance of such FERC order.

[Intentionally omitted.]

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(c)

Seller shall take all necessary steps, including making or supporting timely filings with the FERC in order to maintain, or obtain a FERC waiver of, the Qualifying Cogeneration Facility status of the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation throughout the Term; provided, however, that this obligation does not apply to the extent Seller is unable to maintain Qualifying Cogeneration Facility status using commercially reasonable efforts because of (i) a change in PURPA or in regulations of the FERC implementing PURPA occurring after the Effective Date, or (ii) a change in Applicable Laws directly impacting the Qualifying Cogeneration Facility status of the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation occurring after the Effective Date. The term “commercially reasonable efforts” in this Section 3.17(c) does not require Seller to pay or incur more than $20,000 multiplied by the number of Term Years in the Term.

3.18

3.19

Notice of Cessation or Termination of Service Agreements. Seller shall provide Notice to Buyer within one Business Day if there is a termination of, or cessation of service under, any agreement required in order for the Generating Facility to: (a)

Interconnect with the Transmission Provider’s electric system;

(b)

Transmit and deliver electric energy to the Delivery Point; or

(c)

Own and operate any CAISO-Approved Meter.

Buyer’s Access Rights. (a)

Upon providing at least one Business Day advance Notice to Seller, or as set forth in any Applicable Law (whichever is later), Buyer has the right to examine the Site, the Generating Facility and the Operating records, provided that Buyer follows Seller’s safety policies and procedures that Seller has communicated to Buyer, does not interfere with or hinder Seller’s Operations, and agrees to escorted access to the Generating Facility during regular business hours for: (i)

Any purpose reasonably connected with this Agreement;

(ii)

The exercise of any and all rights of Buyer under Applicable Law or its tariff schedules and rules on file with the CPUC; or

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(iii) (b)

3.20

The inspection and testing of any Check Meter, CAISO-Approved Meter or the Telemetry System.

Seller shall promptly provide Buyer access to all meter data and data acquisition services both in real-time, and at later times, as Buyer may reasonably request. Seller shall promptly inform Buyer of meter quantity changes after becoming aware of, or being informed of, any such changes by the CAISO. Seller shall provide instructions to the CAISO granting authorizations or other documentation sufficient to provide Buyer with access to the CAISO-Approved Meter and to Seller’s settlement data on OMAR.

Seller Financial Information. (a)

The Parties shall determine, through consultation and review with their respective independent registered public accounting firms, whether Buyer is required to consolidate Seller’s financial statements with Buyer’s financial statements for financial accounting purposes under Accounting Standards Codification (ASC) 810/Accounting Standards Update 2009-17, “Consolidation of Variable Interest Entities” (ASC 810), or future guidance issued by accounting profession governance bodies or the SEC that affects Buyer accounting treatment for this Agreement (the “Financial Consolidation Requirement”).

(b)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then: (i)

Within 20 days following the end of each year (for each year that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the year. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements. The annual financial statements should include quarter-to-date and yearly information. Buyer shall provide to Seller a checklist before the end of each year listing the items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the information on the checklist.

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If audited financial statements are prepared for Seller for the year, Seller shall provide such statements to Buyer within five Business Days after those statements are issued. (ii)

Within 15 days following the end of each fiscal quarter (for each quarter that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the quarterly period. The financial statements should include quarter-to-date and year-to-date information. Buyer shall provide to Seller a checklist before the end of each quarter listing items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements.

(iii)

(c)

If Seller regularly prepares its financial data in accordance GAAP, the International Financial Reporting Standards (“IFRS”), or any successor to either of the foregoing (“Successor”), the financial information provided to Buyer shall be prepared in accordance with such principles. If Seller is not a SEC registrant and does not regularly prepare its financial data in accordance with GAAP, IFRS or Successor, the information provided to Buyer shall be prepared in a format consistent with Seller’s regularly applied accounting principles, e.g., the format that Seller uses to provide financial data to its auditor.

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then promptly upon Notice from Buyer, Seller shall allow Buyer’s independent registered public accounting firm such access to Seller’s records and personnel, as reasonably required so that Buyer’s independent registered public accounting firm can conduct financial statement audits in accordance with the standards of the Public Company Accounting Oversight Board (United States), as well as internal control audits in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, as applicable. All expenses for the foregoing shall be borne by Buyer. If Buyer’s independent registered public accounting firm during or as a result of the audits permitted in this Section 3.20(c) determines a material weakness or significant deficiency, as defined by GAAP, IFRS or Successor, as applicable, exists in Seller’s internal controls over financial reporting, then within 90 days of Seller’s receipt of Notice from Buyer, Seller shall remediate any such

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material weakness or significant deficiency; provided, however, that Seller has the right to challenge the appropriateness of any determination of material weakness or significant deficiency. Seller’s true up to actual activity for yearly or quarterly information as provided herein shall not be evidence of material weakness or significant deficiency. (d)

Buyer shall treat Seller’s financial statements and other financial information provided under the terms of this Section 3.20 in strict confidence and, accordingly: (i)

Shall utilize such Seller financial information only for purposes of preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, for making regulatory, tax or other filings required by law in which Buyer is required to demonstrate or certify its or any parent company’s financial condition or to obtain credit ratings;

(ii)

Shall make such Seller financial information available only to its officers, directors, employees or auditors who are responsible for preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, to the SEC and the Public Company Accounting Oversight Board (United States) in connection with any oversight of Buyer’s or any Buyer parent company financial statement and to those Persons who are entitled to receive confidential information as identified in Sections 9.09(a)(vi) and 9.09(a)(vii); and

(iii)

Buyer shall ensure that its internal auditors and independent registered public accounting firm (1) treat as confidential any information disclosed to them by Buyer pursuant to this Section 3.20, (2) use such information solely for purposes of conducting the audits described in this Section 3.20, and (3) disclose any information received only to personnel responsible for conducting the audits.

(e)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then, within two Business Days following the occurrence of any event affecting Seller which Seller understands, during the Term, would require Buyer to disclose such event in a Form 8-K filing with the SEC, Seller shall provide to Buyer a Notice describing such event in sufficient detail to permit Buyer to make a Form 8-K filing.

(f)

If, after consultation and review, the Parties do not agree on issues raised by Section 3.20(a), then such dispute shall be subject to review by another independent audit firm not associated with either Party’s respective independent registered public accounting firm, reasonably acceptable to both Parties. This

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third independent audit firm will render its recommendation on whether consolidation by Buyer is required. Based on this recommendation, Seller and Buyer shall mutually agree on how to resolve the dispute. If Seller fails to provide the data consistent with the mutually agreed upon resolution, Buyer may declare an Event of Default pursuant to Section 6.01. If Buyer’s independent audit firm, after the review by the third independent audit firm still determines that Buyer must consolidate, then Seller shall provide the financial information necessary to permit consolidation to Buyer; provided, however, that in addition to the protections in Section 3.20(d), such information shall be password protected and available only to those specific officers, directors, employees and auditors who are preparing and certifying the consolidated financial statements and not for any other purpose. 3.21

NERC Electric System Reliability Standards. During the Term, for purposes of complying with any NERC Reliability Standards applicable to the Generating Facility, Seller (or an agent of Seller as agreed to by Buyer in its reasonable discretion) must, if required by the NERC, register with the NERC as the Generator Operator and the Generator Owner for the Generating Facility and must perform all Generator Operator Obligations and Generator Owner Obligations except those Generator Operator Obligations that Buyer, in its capacity as Scheduling Coordinator (if Seller has elected to have Buyer serve as its Scheduling Coordinator), is required to perform under this Agreement or under the CAISO Tariff. Notwithstanding anything to the contrary set forth in this Section 3.21 and subject to the indemnity obligations set forth in Section 9.03(h), each Party acknowledges that such Party’s performance of the Generator Operator Obligations or Generator Owner Obligations may not satisfy the requirements for self-certification or compliance with the NERC Reliability Standards, and that it shall be the sole responsibility of each Party to implement the processes and procedures required by the NERC, the WECC, the CAISO, or a Governmental Authority in order to comply with the NERC Reliability Standards. If Buyer is Seller’s Scheduling Coordinator, Buyer as Scheduling Coordinator will reasonably cooperate with Seller to the extent necessary to enable Seller to comply and for Seller to demonstrate Seller’s compliance with the NERC Reliability Standards referenced above. Buyer’s cooperation will include providing to Seller, or such other Person as Seller designates in writing, information in Buyer’s possession that Buyer as Scheduling Coordinator has provided to the CAISO related to the Generating Facility or actions that Buyer has taken as Scheduling Coordinator related to Seller’s compliance with the NERC Reliability Standards referenced above (e.g., Seller’s notices and updates provided by Buyer to the CAISO via SLIC). Buyer may, in its reasonable discretion (depending upon the quantity of information requested by Seller and the timeframe established by Seller for compliance), comply with the requirement to provide information set forth in the previous sentence, by making such information available for

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inspection by Seller or by providing responsive summaries or excerpts of same, so long as the foregoing enables Seller to comply with the NERC Reliability Standards. In addition, Buyer may redact any information or data that is confidential to Buyer from materials or information to be supplied to Seller. 3.22

3.23

Allocation of Availability Incentive Payments and Non-Availability Charges. (a)

If Buyer is the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of Buyer and for Buyer’s account and any Non-Availability Charges will be the responsibility of Buyer and for Buyer’s account.

(b)

If Buyer is not the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of Seller and for Seller’s account and any Non-Availability Charges will be the responsibility of Seller and for Seller’s account.

Seller’s Reporting Requirements. (a)

Seller shall comply with the reporting requirements set forth in Section 3 of Exhibit S.

(b)

Seller shall deliver to Buyer, on or before the 10th Business Day following receipt of a Notice from Buyer, such information that Buyer is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Buyer otherwise requires in order to comply with the Settlement Agreement. *** End of Article Three ***

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ARTICLE FOUR.

BUYER’S OBLIGATIONS

4.01

Obligation to Pay. For Seller’s full compensation under this Agreement, during the Term, Buyer shall make a monthly payment (a “Monthly Contract Payment”) calculated in accordance with Exhibit D.

4.02

Payment Adjustments. (a)

Buyer shall adjust each Monthly Contract Payment to Seller to account for: (i)

Scheduling Fees owed by Seller to Buyer, as set forth in Exhibit G;

(ii)

Any SDD Adjustment, as set forth in Exhibit K;

(iii)

Any Forecast penalties owed by Seller to Buyer, as set forth in Exhibit I;

(iv)

Any CAISO Charges owed by Seller to Buyer, as set forth in Exhibit J;

(v)

Any Physical Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit L;

(vi)

Any SC Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit M;

(vii)

Any payment adjustments (including adjustments to CAISO Charges) provided for under this Agreement;

(viii) Any Governmental Charges owed by either Party to the other Party, as set forth in Section 8.02;

(b)

(ix)

The agreement of the Parties that Buyer shall have no liability to make any energy payments to Seller for any electricity deliveries from the Generating Facility in a Term Year that exceed 120% of Expected Term Year Energy Production; and

(x)

Any payment adjustments provided for to determine Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges, as set forth in Exhibit S.

Unless otherwise required in Exhibit S, during the Term, any payment adjustments will be added to or deducted from a subsequent regular Monthly Contract Payment that is made by Buyer to Seller after the expiration of a 30-day period which begins upon Buyer’s receipt of all of the information required in order to calculate payment adjustments.

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(c)

4.03

Unless otherwise required in Exhibit S, after the Term End Date, Buyer shall invoice Seller for all payment adjustments within 60 days of Buyer’s receipt of all of the information required in order to calculate payment adjustments.

Payment Statement and Payment. (a)

No later than 30 days after the end of each calendar month (or the last day of the month if the month in which the payment statement is being sent is February), or the last Business Day of the month if such 30th day (or 28th or 29th day for February) is not a Business Day, Buyer shall mail to Seller: (i)

(ii)

(iii)

A table showing the hourly electric energy quantities for each of the following, in MWh per hour: 1)

Seller’s Energy Forecast;

2)

Seller’s Day-Ahead Forecast;

3)

Metered Energy;

4)

Metered Amounts;

5)

The final Buyer Energy Schedule; and

6)

The final Buyer Parent Energy Schedule.

A statement showing: 1)

TOD Period subtotals and overall monthly totals for each of the items set forth in Section 4.03(a)(i);

2)

A calculation of the Monthly Contract Payment, as set forth in Exhibit D;

3)

A calculation of any payment adjustments pursuant to Section 4.02;

4)

A calculation of any payment adjustments pursuant to Exhibit S; and

5)

A calculation of the net dollar amount due for the month.

Buyer’s payment to Seller, in accordance with Section 9.15, in the net dollar amount owed to Seller for the month (less any overpayments by

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Buyer of Seller’s GHG Compliance Costs or GHG Charges under Section 4.04 in any calendar month); provided, however, in the event the statement shows a net amount owed to Buyer, Seller shall pay such amount within 20 days of the statement date or, if Seller fails to make such payment, Buyer may offset this amount from a subsequent Monthly Contract Payment. (b)

If Buyer determines that a calculation of Metered Energy or Metered Amounts is incorrect as a result of an inaccurate meter reading or the correction of data by the CAISO in the CAISO’s meter-data acquisition and processing system, Buyer shall promptly recompute the Metered Energy or Metered Amounts quantity for the period of the inaccuracy based on an adjustment of such inaccurate meter reading in accordance with the CAISO Tariff. Buyer shall then promptly recompute any payment or payment adjustment affected by such inaccuracy. Any amount due from Buyer to Seller or Seller to Buyer, as the case may be, shall be made as an adjustment to the next monthly statement that is calculated after Buyer’s recomputation using corrected measurements. If the recomputation results in a net amount owed to Buyer after offsetting any amounts owing to Seller as shown on the next monthly statement, any such additional amount still owing to Buyer shall be shown as an adjustment on Seller’s monthly statement until such amount is fully collected by Buyer. At Buyer’s sole discretion, Buyer may offset any remaining amount owed to Buyer in any subsequent monthly payments to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice.

(c)

(d)

Buyer reserves the right to deduct amounts that would otherwise be due to Seller under this Agreement from any amounts owing and unpaid by Seller to Buyer: (i)

Under this Agreement; or

(ii)

Arising out of or related to any other agreement, tariff, obligation or liability pertaining to the Generating Facility.

Except as provided in Section 4.03(b) and as otherwise provided in this Section 4.03(d), if, within 45 days of receipt of Buyer’s payment statement, Seller does not give Notice to Buyer of an error, then Seller shall be deemed to have waived any error in Buyer’s statement, computation and payment and the statement shall be conclusively deemed correct and complete; provided, however, that if an error

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is identified by Seller as a result of settlement, audit or other information provided to Seller by the CAISO after the expiration of the original 45-day period, Seller shall have an additional 90 days from the date on which it receives the information from the CAISO in which to give Notice to Buyer of the error identified by such settlement, audit or other information. If Seller identifies an error in Seller’s favor and Buyer agrees that the identified error occurred, Buyer shall reimburse Seller for the amount of the underpayment caused by the error and add the underpayment to the next monthly statement that is calculated. If Seller identifies an error in Buyer’s favor and Buyer agrees that the identified error occurred, Seller shall reimburse Buyer for the amount of overpayment caused by the error and Buyer shall apply the overpayment to the next monthly statement that is calculated. If the recomputation results in a net amount still owing to Buyer after applying the overpayment, the next monthly statement shall show a net amount owing to Buyer. At Buyer’s sole discretion, Buyer may apply this net amount owing to Buyer in any subsequent monthly statements to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice. The Parties shall negotiate to resolve any disputes regarding claimed errors in a statement. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. Nothing in this Section 4.03 limits a Party’s rights under applicable tariffs, other agreements or Applicable Law.

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4.04

GHG Compliance Costs. Buyer shall pay for Seller’s GHG Compliance Costs and GHG Charges in accordance with Exhibit S; provided, however, that notwithstanding anything to the contrary set forth in this Agreement (including Exhibit S), in no event will Buyer pay for any of Seller’s GHG Compliance Costs or GHG Charges to the extent that such GHG Compliance Costs or GHG Charges are associated with deliveries of the Power Product that are in excess of 120% of the Expected Term Year Net Energy Production in any Term Year.

4.05

No Representation by Buyer. Any review by Buyer of the design, engineering, construction, testing and Operation of the Generating Facility is solely for Buyer’s information. Buyer makes no representation that: (a)

It has reviewed the financial viability, technical feasibility, operational capability, or long term reliability of the Generating Facility;

(b)

The Generating Facility complies with any Applicable Laws; or

(c)

The Generating Facility will be able to meet the terms of this Agreement.

Seller shall in no way represent to any third party that any such review by Buyer constitutes any such representation. 4.06

Buyer’s Responsibility. Buyer shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable transmission and delivery of electric energy at and after the Delivery Point.

4.07

Buyer’s Reporting Requirements. Buyer shall deliver to Seller, on or before the 10th Business Day following receipt of a Notice from Seller, such information as Seller is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Seller otherwise requires in order to comply with the Settlement Agreement. *** End of Article Four ***

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ARTICLE FIVE.

FORCE MAJEURE

5.01

No Default for Force Majeure. Neither Party will be in default in the performance of any of its obligations set forth in this Agreement, except for obligations to pay money, when and to the extent failure of performance is caused by Force Majeure.

5.02

Requirements Applicable to the Claiming Party. If a Party, because of Force Majeure, is rendered wholly or partly unable to perform its obligations when due under this Agreement, such Party (the “Claiming Party”) shall be excused from whatever performance is affected by the Force Majeure to the extent so affected. In order to be excused from its performance obligations under this Agreement by reason of Force Majeure: (a)

The Claiming Party, within 14 days after the initial occurrence of the claimed Force Majeure, must give the other Party Notice describing the particulars of the occurrence; and

(b)

The Claiming Party must provide timely evidence reasonably sufficient to establish that the occurrence constitutes Force Majeure as defined in this Agreement.

The suspension of the Claiming Party’s performance due to Force Majeure may not be greater in scope or longer in duration than is required by such Force Majeure. In addition, the Claiming Party shall use diligent efforts to remedy its inability to perform. This Article Five will not require the settlement of any strike, walkout, lockout or other labor dispute on terms which, in the sole judgment of the Claiming Party, are contrary to its interest. It is understood and agreed that the settlement of strikes, walkouts, lockouts or other labor disputes shall be at the sole discretion of the Claiming Party. When the Claiming Party is able to resume performance of its obligations under this Agreement, the Claiming Party shall give the other Party prompt Notice to that effect. 5.03

Termination. Either Party may terminate this Agreement on Notice, which Notice will be effective five Business Days after such Notice is provided, in the event of Force Majeure which materially interferes with such Party’s ability to perform its obligations under this Agreement and which extends for more than 365 consecutive days, or for more than a total of 365 days in any consecutive 540-day period. *** End of Article Five ***

Article Five

Force Majeure

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ARTICLE SIX. 6.01

EVENTS OF DEFAULT; REMEDIES

Events of Default. An “Event of Default” means the occurrence of any of the following :

(a)

With respect to either Party (a “Defaulting Party”): (i) Any representation or warranty made by such Party in this Agreement is false or misleading in any material respect when made or when deemed made or repeated if the representation or warranty is continuing in nature, if such misrepresentation or breach of warranty is not:

1) Remedied within 10 Business Days after Notice from the Non-Defaulting Party to the Defaulting Party; or 2) Capable of a cure, but the Non-Defaulting Party’s damages resulting from such misrepresentation or breach of warranty can reasonably be ascertained and the payment of such damages is not made within 10 Business Days after a Notice of such damages is provided by the Non-Defaulting Party to the Defaulting Party; (ii) Except for an obligation to make payment when due, the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default or to the extent excused by a Force Majeure) if such failure is not remedied within 30 days after Notice of such failure is provided by the Non-Defaulting Party to the Defaulting Party, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 30-day cure period, the Defaulting Party shall have such additional time (not to exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as such Defaulting Party promptly commences and diligently pursues such cure; (iii) A Party fails to make when due any payment (other than amounts disputed in accordance with the terms of this Agreement) due and owing under this Agreement and such failure is not cured within five Business Days after Notice is provided by the Non-Defaulting Party to the Defaulting Party of such failure; (iv)

A Party becomes Bankrupt; or

(v) A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another Person and, at the time of such consolidation, amalgamation, merger or transfer, the resulting,

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surviving or transferee Person fails to assume all the obligations of such Party under this Agreement to which such Party or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party.; (vi) An event of default occurs (howsoever determined) under any agreement between Buyer and Seller (other than this Agreement but including the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation) and, after giving effect to any applicable notice requirement or cure period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that agreement; or (vii) The Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, the Transition EEI Agreement or the Transition Tolling Confirmation or Transition RA Confirmation. (b)

[Intentionally omitted.]

(c)

With respect to Seller: (i) Seller does not own or lease the Generating Facility or otherwise have the authority over the Generating Facility as required in Section 3.03, and Seller has not cured a failure with respect to Section 3.03 within 30 days after providing Notice to Buyer in accordance with Section 3.03; (ii) If Seller abandons the Generating Facility (for purposes of this Section 6.01(c)(ii), Seller will be deemed to have abandoned the Generating Facility if Seller has ceased work on the Generating Facility or the Generating Facility has ceased production and delivery of the Product for a consecutive thirty (30) day period and such cessation is not a result of an event of Force Majeure); (iii) ExceptDuring the Term, except as provided for in Section 3.01(d), Seller (1) conveys, transfers, allocates, designates, awards, reports or otherwise provides any and all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except as may relate to transactions in the imbalance market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) starts up or Operates the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws);

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(iv) Seller intentionally or knowingly delivers, Schedules, or attempts to deliver or Schedule at the Delivery Point for sale under this Agreement electric energy that was not generated by the Generating Facility; (v) Seller removes from the Site equipment upon which the Net Contract Capacity has been based, except for the purposes of replacement, refurbishment, repair, repowering or maintenance, and such equipment is not returned within five Business Days after Notice from Buyer to Seller; (vi) Subject to Section 3.17(c), the Generating Facility fails to maintain its status as a Qualifying Cogeneration Facility; (vii) Termination of, or cessation of service under, any agreement necessary for the interconnection of the Generating Facility to the Transmission Provider’s electric system for transmission and delivery of the electric energy from the Generating Facility to the Delivery Point, or for metering the Metered Energy, and such service is not reinstated, or alternative arrangements implemented, within 120 days after such termination or cessation; (viii) Seller fails to make all reasonable efforts to increase the Power Output from the Generating Facility to the Firm Contract Capacity during an Emergency Condition or a System Emergency; (ix) Seller fails to provide any financial statements or other information within the timeframe and in the manner set forth in Sections 3.20(b)(i) and (ii), and such failure is not remedied within 10 days after Notice from Buyer to Seller; (x) Seller fails to remediate any material weakness or significant deficiency in internal controls over financial reporting in accordance with Section 3.20(c), and such failure is not remedied within 90 days after Notice from Buyer to Seller; (xi) Seller fails to take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term as specified in Section 3.01, if such failure is not remedied within 10 days after Notice of such failure is provided by Buyer to Seller, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 10-day cure period, Seller shall have such additional time (not to

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exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as Seller promptly commences and diligently pursues such cure; (xii)

[Intentionally omitted]

(xiii) If any failure by Seller to comply with the CAISO Tariff materially impacts Buyer’s ability to comply with this Agreement, the CAISO Tariff or other Applicable Laws, and such failure by Seller (including any consequences suffered by Buyer) is not cured within 30 days after Notice from Buyer to Seller; (xiv) If Seller materially modifies or repowers the Generating Facility (except as provided in Section 3.07(c)) without Buyer’s prior written consent; or (xv) If Seller fails to satisfy all of the conditions set forth in Section 2.01 before the Term Start Date, and such failure is not cured within 30 Business Days after Notice from Buyer to Seller. 6.02 Early Termination. If an Event of Default has occurred, there will be no opportunity for cure except as specified in Section 6.01 or pursuant to a Collateral Assignment Agreement agreed upon by Buyer, Seller and Lender in accordance with Section 9.05. The Party taking the default (the “Non-Defaulting Party”) will have the right to: (a) Designate by Notice to the Defaulting Party a date, no later than 20 days after the Notice is effective, for the early termination of this Agreement (an “Early Termination Date”); (b)

Immediately suspend performance under this Agreement; and

(c) Pursue all remedies available at law or in equity against the Defaulting Party (including monetary damages), except to the extent that such remedies are limited by the terms of this Agreement. 6.03 Termination Payment. As soon as practicable after an Early Termination Date is declared, the Non-Defaulting Party shall provide Notice to the Defaulting Party of the sum of all amounts owed by the Defaulting Party under this Agreement less any amounts owed by the NonDefaulting Party to the Defaulting Party under this Agreement, including any Forward Settlement Amount (the “Termination Payment”). The Notice shall include a written statement setting forth, in reasonable detail, the calculation of such Termination Payment, including the Forward Settlement Amount, together with appropriate supporting documentation. If the Termination Payment is positive, the Defaulting Party shall pay such amount to the Non-Defaulting Party within 10 Business Days after the Notice is provided. If the Termination Payment is negative (i.e., the Non-Defaulting Party owes the Defaulting Article Six

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Party more than the Defaulting Party owes the Non-Defaulting Party), then the NonDefaulting Party shall pay such amount to the Defaulting Party within 10 Business Days after the Notice is provided. The Parties shall negotiate to resolve any disputes regarding the calculation of the Termination Payment and Forward Settlement Amount. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. *** End of Article Six ***

Article Six

Events of Default; Remedies

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ARTICLE SEVEN. LIMITATIONS OF LIABILITIES EXCEPT AS SET FORTH IN THIS ARTICLE SEVEN, THERE ARE NO WARRANTIES BY EITHER PARTY UNDER THIS AGREEMENT, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY IS LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED, UNLESS THE PROVISION IN QUESTION PROVIDES THAT THE EXPRESS REMEDIES ARE IN ADDITION TO OTHER REMEDIES THAT MAY BE AVAILABLE. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, THE OBLIGOR’S LIABILITY IS LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. THE VALUE OF ANY PRODUCTION TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. THE VALUE OF ANY INVESTMENT TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. UNLESS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, INCLUDING THE PROVISIONS OF SECTION 9.03, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS IMPOSED IN THIS ARTICLE SEVEN ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE.

Article Seven

Limitations of Liabilities

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TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID UNDER THIS AGREEMENT ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED UNDER THIS AGREEMENT CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. NOTHING IN THIS ARTICLE SEVEN PREVENTS, OR IS INTENDED TO PREVENT BUYER FROM PROCEEDING AGAINST OR EXERCISING ITS RIGHTS WITH RESPECT TO ANY SECURED INTEREST IN COLLATERAL. *** End of Article Seven ***

Article Seven

Limitations of Liabilities

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ARTICLE EIGHT. GOVERNMENTAL CHARGES 8.01

Cooperation to Minimize Tax Liabilities. Each Party shall use diligent efforts to implement the provisions of and to administer this Agreement in accordance with the intent of the Parties to minimize all taxes, so long as neither Party is materially adversely affected by such efforts.

8.02

Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any Governmental Authority (“Governmental Charges”) on or with respect to the Generating Facility, Monthly Contract Payments made by Buyer to Seller, or the Power Product before the Delivery Point, including ad valorem taxes and other taxes attributable to the Generating Facility, the Site or land rights or interests in the Site or the Generating Facility. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Power Product at and after the Delivery Point. If Seller is required by Applicable Laws to remit or pay Governmental Charges which are Buyer’s responsibility under this Agreement, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by Applicable Law or regulation to remit or pay Governmental Charges which are Seller’s responsibility under this Agreement, Buyer may deduct such amounts from payments to Seller made pursuant to Article Four. If Buyer elects not to deduct such amounts from Seller’s payments, Seller shall promptly reimburse Buyer for such amounts upon Notice from Buyer of the amount to be reimbursed. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under Applicable Laws. Nothing stated in this Section 8.02 relieves Buyer of its obligation to pay Seller for Seller’s GHG Compliance Costs and GHG Charges in accordance with and subject to this Agreement (including Exhibit S).

8.03

Providing Information to Taxing Governmental Authorities. To the extent required by Applicable Law and subject to Section 9.09(b), each Party shall provide information concerning the Generating Facility to any requesting taxing Governmental Authority. *** End of Article Eight ***

Article Eight

Governmental Charges

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ARTICLE NINE.

MISCELLANEOUS

9.01

Representations, Warranties and Covenants.

(a)

On the Effective Date, each Party represents and warrants to the other Party that:

(i)

It is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;

(ii)

The execution, delivery and performance of this Agreement are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any Applicable Laws;

(iii)

This Agreement constitutes a legally valid and binding obligation enforceable against it in accordance with its terms, subject to any Equitable Defenses;

(iv)

There is not pending, or to its knowledge, threatened against it or, in the case of Seller, any of its Related Entities, any legal proceeding that could materially adversely affect its ability to perform under this Agreement;

(v)

No Event of Default with respect to it has occurred and is continuing and no such event or circumstance will occur as a result of its entering into or performing its obligations under this Agreement;

(vi)

It is acting for its own account, and its decision to enter into this Agreement is based upon its own judgment, not in reliance upon the advice or recommendations of the other Party and it is capable of assessing the merits of and understanding, and understands and accepts the terms, conditions and risks of this Agreement;

(vii)

It has not relied on any promises, representations, statements or information of any kind whatsoever that are not contained in this Agreement in deciding to enter into this Agreement; and

(viii) It has entered into this Agreement in connection with the conduct of its business and it has the capacity or ability to provide or receive the Power Product as contemplated by this Agreement. (b)

On the Effective Date, each Party covenants to the other Party that, except for CPUC Approval in the case of Buyer, and for certain authorizations that Seller will need to obtain from FERC, it has or will timely acquire all regulatory authorizations necessary for it to legally perform its obligations under this Agreement.

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(c)

On the Effective Date, Seller represents and warrants to Buyer that the Generating Facility is an Existing Qualifying Cogeneration Facility.

9.02

Additional Covenants by Seller. Seller covenants to Buyer that:

(a)

It will have Site Control as of the earlier of (i) the Term Start Date and (ii) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term;

(b)

Throughout the Term, it or its subcontractors will own or lease and Operate the Generating Facility unless otherwise agreed to by the Parties;

(c)

Throughout the Term, it will deliver the Product to Buyer free and clear of all liens, security interests, Claims and encumbrances or any interest therein or thereto by any Person;

(d)

Throughout the Term, it will hold the rights to all of the Product, subject to the terms of this Agreement;

(e)

From the Effective Date until the Term End Date, the Generating Facility will maintain its status as a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(f)

Throughout the Term, it will not (1) convey, transfer, allocate, designate, award, report or otherwise provide any or all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except, if Buyer is not Scheduling Coordinator, as may relate to transactions in the Real-Time Market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) start-up or Operate the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws); and

(g)

Seller shall comply with all (i) applicable cap-and-trade programs for the regulation of Greenhouse Gas, as established by any Governmental Authority pursuant to federal or state legislation, and (ii) other applicable programs regulating Greenhouse Gas emissions.

9.03

Indemnity.

(a)

Each Party as indemnitor shall defend, save harmless and indemnify the other Party and the directors, officers, employees, and agents of such other Party against and from any and all loss, liability, damage, claim, cost, charge, demand,

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or expense (including any direct, indirect, or consequential loss, liability, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees) for injury or death to Persons, including employees of either Party, and physical damage to property including property of either Party arising out of or in connection with the negligence or willful misconduct of the indemnitor relating to its obligations under this Agreement. This indemnity applies notwithstanding the active or passive negligence of the indemnitee. However, neither Party is indemnified under this Agreement for its loss, liability, damage, claim, cost, charge, demand or expense to the extent resulting from its negligence or willful misconduct. (b)

Each Party releases and shall defend, save harmless and indemnify the other Party from any and all loss, liability, damage, claim, cost, charge, demand or expense arising out of or in connection with any breach made by the indemnifying Party of its representations, warranties and covenants in Section 9.01 and Section 9.02.

(c)

The provisions of this Section 9.03 may not be construed to relieve any insurer of its obligations to pay any insurance Claims in accordance with the provisions of any valid insurance policy.

(d)

Notwithstanding anything to the contrary in this Agreement, if Seller fails to comply with the provisions of Section 9.10, Seller shall, at its own cost, defend, save harmless and indemnify Buyer, its directors, officers, employees, and agents, assigns, and successors in interest, from and against any and all loss, liability, damage, claim, cost, charge, demand, or expense of any kind or nature (including any direct, indirect, or consequential loss, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees and other costs of litigation), resulting from injury or death to any person or damage to any property, including the personnel or property of Buyer, to the extent that Buyer would have been protected had Seller complied with all of the provisions of Section 9.10. The inclusion of this Section 9.03(d) is not intended to create any express or implied right in Seller to elect not to provide the insurance required under Section 9.10.

(e)

Each Party shall defend, save harmless and indemnify the other Party against any Governmental Charges for which such indemnifying Party is responsible under Article Eight.

(f)

Seller shall defend, save harmless and indemnify Buyer against any increase in GHG Compliance Costs and other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating

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Facility to the extent that such GHG Compliance Costs or other costs result from Seller’s modification or repowering of the Generating Facility in accordance with Section 3.07. (g)

Seller shall defend, save harmless and indemnify Buyer against any penalty imposed upon Buyer as a result of Seller’s failure to fulfill its obligations regarding Resource Adequacy Benefits as set forth in Sections 3.01 and 3.02, with the exception of the obligations set forth in Section 3.01(c)(vi).

(h)

Seller is solely responsible for any NERC Standards Non-Compliance Penalties arising from or relating to Seller’s failure to perform the Generator Operator Obligations or the Generator Owner Obligations for which Seller is responsible, in accordance with Section 3.21, and will indemnify, defend and hold Buyer harmless from and against all liabilities, damages, Claims, losses, and reasonable costs and expenses (which shall include reasonable costs and expenses of outside or in-house counsel) incurred by Buyer arising from or relating to Seller’s actions or inactions that result in NERC Standards Non-Compliance Penalties or an attempt by any Governmental Authority, Person to assess such NERC Standards Non-Compliance Penalties against Buyer. Buyer will indemnify, defend and hold Seller harmless from and against all liabilities, damages, Claims, losses and reasonable costs and expenses (which shall include reasonable costs of outside and in-house counsel) incurred by Seller for any NERC Standards NonCompliance Penalties to the extent they are due to Buyer’s negligence or willful misconduct in performing its role as Seller’s Scheduling Coordinator during the Term.

(i)

All indemnity rights will survive the termination of this Agreement for 12 months.

9.04

Assignment.

(a)

With Consent. Subject to Section 9.04(b), Seller may not transfer or assign this Agreement or its rights under this Agreement without the prior written consent of Buyer, which consent may not be unreasonably withheld or delayed. Any direct or indirect change of control of Seller (whether voluntary or by operation of law) will be deemed an assignment and will require the prior written consent of Buyer, which consent will not be unreasonably withheld. For purposes of this Section 9.04, Buyer will not withhold its consent to an indirect change of control of Seller if Seller demonstrates to Buyer’s reasonable satisfaction that Seller shall continue to perform its obligations under this Agreement as if no such indirect change of control had occurred.

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(b)

Without Consent. Notwithstanding anything to the contrary set forth in Section 9.04(a):

(i)

Seller may, without the consent of Buyer (and without relieving itself from liability hereunder): (1) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements in accordance with Section 9.05; or (2) transfer or assign this Agreement to ana Related Entity of Seller, which Related Entity’s creditworthiness is equal to or higher than that of Seller; and

(ii)

Seller does not need to obtain Buyer’s consent to any change of control described in this Section 9.04 if such change of control results from a purchase of the outstanding shares of a publicly traded company.

9.05

Consent to Collateral Assignment. Subject to the provisions of this Section 9.05, Seller may (but is not obligated to) assign this Agreement as collateral to a Lender for any financing or refinancing of the Generating Facility, including a SaleLeaseback Transaction or Equity Investment and, in connection therewith, Buyer shall in good faith work with Seller and Lender to agree upon a consent to a collateral assignment of this Agreement or to a Sale-Leaseback Transaction or Equity Investment, as applicable (“Collateral Assignment Agreement”).

The Collateral Assignment Agreement shall be in form and substance reasonably agreed to by Buyer, Seller and Lender, and shall include, among others, the following provisions (together with such other commercially reasonable provisions required by any Lender that are reasonably acceptable to Buyer): (a)

Buyer shall give, to the Person(s) to be specified by Lender in the Collateral Assignment Agreement, simultaneously with the Notice to Seller and before exercising its right to terminate this Agreement, written Notice of any event or circumstance known to Buyer which would, if not cured within the applicable cure period specified in Article VI, constitute an Event of Default (an “Incipient Event of Default”);

(b)

Lender shall have the right to cure an Incipient Event of Default or an Event of Default by Seller in accordance with the same provisions of this Agreement as apply to Seller;

(c)

Following an Event of Default by Seller under this Agreement, Buyer may require Seller to (although Lender may, but shall have no obligation, subject to 9.05(g)) provide to Buyer a report concerning:

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(i)

The status of efforts by Seller or Lender to develop a plan to cure the Event of Default;

(ii)

Impediments to the cure plan or its development;

(iii)

If a cure plan has been adopted, the status of the cure plan’s implementation (including any modifications to the plan as well as the expected timeframe within which any cure is expected to be implemented); and

(iv)

Any other information which Buyer may reasonably require related to the development, implementation and timetable of the cure plan;

(d)

Seller or Lender shall provide the report to Buyer within 10 Business Days after Notice from Buyer requesting the report. Buyer shall have no further right to require the report with respect to a particular Event of Default after that Event of Default has been cured;

(e)

Lender shall have the right to cure an Event of Default or Incipient Event of Default on behalf of Seller, only if Lender sends a written notice to Buyer before the end of any cure period indicating Lender’s intention to cure. Lender may remedy or cure the Event of Default or Incipient Event of Default within the cure period under this Agreement. Such cure period for Lender shall be extended for each day Buyer does not provide the Notice to Lender referred to in Section 9.05(a). In addition, such cure period may, in Buyer’s reasonable discretion, be extended by no more than an additional 180 days. If possession of the Generating Facility is necessary to cure such Incipient Event of Default or Event of Default, Lender has commenced foreclosure proceedings within 60 days after receipt of such Notice from Buyer, and Lender is making diligent and consistent efforts to complete such foreclosure, take possession of the Generating Facility and promptly cure the Incipient Event of Default or Event of Default, Lender or its designee(s) or assignee(s) will be allowed a reasonable period of time to complete such foreclosure proceedings, take possession of the Generating Facility and cure such Incipient Event of Default or Event of Default, not to exceed 180 days after Lender’s commencement of foreclosure. Additionally, if Lender is prohibited from curing any Incipient Event of Default or Event of Default by any process, stay or injunction issued by a Governmental Authority or pursuant to any bankruptcy, insolvency or similar proceedings, then the time period for curing such Incipient Event of Default or Event of Default shall be extended for the period of the prohibition provided that Lender is exercising reasonable diligence in having such process, stay or injunction removed;

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(f)

Lender shall have the right to consent before any termination of this Agreement which does not arise out of an Event of Default or the end of the Term;

(g)

Lender shall receive prior Notice of, and shall have the right to approve material amendments to this Agreement, which approval may not be unreasonably withheld, delayed or conditioned;

(h)

In the event Lender, directly or indirectly, takes title to the Generating Facility (including title by foreclosure or deed in lieu of foreclosure), the Person taking title to the Generating Facility shall assume all of Seller’s obligations arising under this Agreement and all related agreements (subject to such limits on liability as are mutually agreed to by Seller, Buyer and Lender as set forth in the Collateral Assignment Agreement); provided, however, that Lender (or such Person) shall have no liability for any monetary obligations of Seller under this Agreement which are due and owing to Buyer as of the assumption date (but this provision may not be interpreted to limit Buyer’s rights to proceed against Seller as a result of an Event of Default) and Lender’s (or such Person’s) liability to Buyer after such assumption shall be limited to its interest in the Generating Facility; provided further, that before such assumption, if Buyer advises Lender (or such Person) that Buyer will require that Lender (or such Person) cure (or cause to be cured) one or more monetary or non-monetary Incipient Event(s) of Default or Event(s) of Default existing as of the date such Person takes title in order to avoid the exercise by Buyer (in its sole discretion) of Buyer’s right to terminate this Agreement with respect to such Incipient Event(s) of Default or Event(s) of Default, then Lender (or such Person) at its option and in its sole discretion may elect to either (i) cause such Incipient Event(s) of Default or Event of Default to be cured, or (ii) not assume this Agreement;

(i)

If Lender has assumed this Agreement as provided in Section 9.05(h) and elects to sell or transfer the Generating Facility (after Lender directly or indirectly, takes title to the Generating Facility), or sale of the Generating Facility occurs through the actions of Lender or an agent of or representative of Lender (excluding any foreclosure sale where a third party other than Lender, Seller, an Related Entity of Lender or an Related Entity of Seller is the buyer), then Lender must cause the transferee or buyer to assume all of Seller’s obligations arising under this Agreement and all related agreements as a condition of the sale or transfer excluding, however, a foreclosure (unless the transferee or buyer is Lender, Seller, an Related Entity of Lender or an Related Entity of Seller). Lender shall be released from all further obligations under the Agreement and all related documents following such assumption. Such sale or transfer (excluding a foreclosure) may be made only to a Person reasonably acceptable to Buyer; and

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(j)

If this Agreement is rejected in Seller’s Bankruptcy or otherwise terminated in connection therewith and if Lender or its representative or designee, directly or indirectly, takes title to the Generating Facility, then, at the request of either Buyer or Lender, Buyer and Lender (or its designee or representative) shall promptly enter into a new agreement with Buyer having substantially the same terms as this Agreement for the term that would have been remaining under this Agreement, provided that Lender’s (or its designee’s or representative’s) liability under such new agreement shall be limited to its interest in the Generating Facility and neither Lender (or its designee or representative) nor Buyer shall have any personal liability to the other for any amounts owing and neither Buyer nor Lender (or its designee or representative) shall have any obligation to cure any defaults under the original Agreement that was rejected in, or otherwise terminated in connection with Seller’s Bankruptcy.

9.06

Governing Law and Jury Trial Waiver. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER ARE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. TO THE EXTENT ENFORCEABLE AT SUCH TIME, EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT.

9.07

Notices. All Notices shall be provided as specified in Exhibit N. Notices (other than Forecasts and Scheduling requests) shall, unless otherwise specified in this Agreement, be in writing and may be delivered by hand delivery, first class United States mail, overnight courier service, electronic transmission or facsimile. Notices provided in accordance with this Section 9.07 are deemed given as follows:

(a)

Notice by facsimile, electronic transmission or hand delivery is deemed given at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise are deemed given at the close of business on the next Business Day;

(b)

Notice by overnight first class United States mail or overnight courier service is deemed given on the next Business Day after such Notice is sent out;

(c)

Notice by first class United States mail is deemed given two Business Days after the postmarked date;

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(d)

Notices are effective on the date deemed given, unless a different date for the Notice to go into effect is stated in another section of this Agreement;

(e)

A Party may change its designated representatives, addresses and other contact information by providing Notice of same in accordance herewith; and

(f)

All Notices for this Generating Facility must reference the identification number set forth on the cover page of this Agreement.

9.08

General.

(a)

This Agreement supersedes all prior agreements, whether written or oral, between the Parties with respect to its subject matter and constitutes the entire agreement between the Parties relating to its subject matter.

(b)

This Agreement will not be construed against any Party as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof.

(c)

Except to the extent provided for in this Agreement, no amendment or modification to this Agreement is enforceable unless reduced to a writing signed by all Parties.

(d)

If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement will remain in full force and effect. Any provision of this Agreement held invalid or unenforceable only in part or degree will remain in full force and effect to the extent not held invalid or unenforceable.

(e)

Waiver by a Party of any default by the other Party will not be construed as a waiver of any other default.

(f)

The term “including” when used in this Agreement is by way of example only and will not be considered in any way to be in limitation.

(g)

The word “or” when used in this Agreement includes the meaning “and/or” unless the context unambiguously dictates otherwise.

(h)

The headings used in this Agreement are for convenience and reference purposes only and will not affect its construction or interpretation. All references to “Articles”, “Sections” and “Exhibits” refer to the corresponding Articles, Sections and Exhibits of this Agreement. Unless otherwise specified, all references to “Articles” or “Sections” in Exhibits A through T refer to the corresponding Articles and Sections in the main body of this Agreement. Words having well-

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known technical or industry meanings have such meanings unless otherwise specifically defined in this Agreement. (i)

Where days are not specifically designated as Business Days, they are calendar days. Where years are not specifically designated as Term Years, they are calendar years.

(j)

This Agreement will apply to, be binding in all respects upon and inure to the benefit of the successors and permitted assigns of the Parties. Nothing in this Agreement will be construed to give any Person other than the Parties any legal or equitable right, remedy or claim under or with respect to this Agreement or any provision of this Agreement, except as shall inure to a successor or permitted assignee.

(k)

No provision of this Agreement is intended to contradict or supersede any applicable agreement between the Parties or between or among Seller, the CAISO and the Transmission Provider, covering transmission, distribution, metering, scheduling or interconnection of electric energy (including the PGA and QF PGA). In the event of an apparent contradiction between this Agreement and any such agreement, the applicable agreement controls.

(l)

Whenever this Agreement specifically refers to any law, tariff, government department or agency, regional reliability council, Transmission Provider, or credit rating agency, the Parties agree that the reference also refers to any successor to such law, tariff or organization.

(m)

The Parties acknowledge and agree that this Agreement and the transactions contemplated by this Agreement constitute a “forward contract” within the meaning of the United States Bankruptcy Code and that Buyer and Seller are each “forward contract merchants” within the meaning of the United States Bankruptcy Code.

(n)

This Agreement may be executed in one or more counterparts, each of which will be deemed to be an original of this Agreement and all of which, when taken together, will be deemed to constitute one and the same agreement. The exchange of copies of this Agreement and of signature pages by facsimile transmission, an Adobe Acrobat file or by other electronic means constitutes effective execution and delivery of this Agreement as to the Parties and may be used in lieu of the original Agreement for all purposes. Signatures of the Parties transmitted by facsimile or by other electronic means will be deemed to be their original signatures for all purposes.

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(o)

The Parties acknowledge that neither Party is waiving any right it may have under the Settlement Agreement.

9.09

Confidentiality.

(a)

Neither Party may disclose any Confidential Information to a third party, other than:

(i)

To such Party’s employees, Lenders, investors, attorneys, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential;

(ii)

To potential Lenders with the consent of Buyer, which consent will not be unreasonably withheld; provided, however, that disclosure (1) of cash flow and other financial projections to any potential Lender or investor in connection with a potential loan or tax equity investment; or (2) to potential Lenders or investors with whom Seller has negotiated (but not necessarily executed) a term sheet or other similar written mutual understanding, will not require such consent of Buyer; provided further, that in each case such potential Lender or investor has a need to know such information and has agreed to keep such terms confidential;

(iii)

To Buyer’s Procurement Review Group, as defined in D.02-08-071, or Buyer’s Cost Allocation Mechanism Group, as defined in D.06-07-029 and D.08-09-012, and pursuant to the Settlement Agreement and related Decisions, subject to a protective order applicable to Buyer’s Procurement Review Group; or Buyer’s Cost Allocation Mechanism Group;

(iv)

With respect to Confidential Information other than nonpublic financial information of Seller supplied to Buyer pursuant to Section 3.20, to the CPUC, the CEC or the FERC, under seal for any regulatory purpose, including policymaking, but only provided that the confidentiality protections from the CPUC under Section 583 of the California Public Utilities Code or other statute, order or rule offering comparable confidentiality protection are in place before the communication of such Confidential Information;

(v)

In order to comply with any Applicable Law or any exchange, Control Area or CAISO rule, or order issued by a court or entity with competent jurisdiction over the disclosing party, other than to those entities set forth in Section 9.09(a)(vi);

(vi)

In order to comply with any Applicable Law, including applicable regulation, rule, subpoena, or order of the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, or any discovery or data request of the CPUC;

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(vii)

To representatives of a Party’s credit ratings agencies who have a need to review the terms and conditions of this Agreement for the purpose of assisting the Party in evaluating this Agreement for credit rating purposes or with respect to the potential impact of this Agreement on the Party’s financial reporting obligations, in each case subject to confidentiality restrictions no less stringent than as set forth in this Agreement; and

(viii) As may reasonably be required to participate in WREGIS or other process recognized under Applicable Laws for the registration, transfer or ownership of Green Attributes associated with the Related Products. (b)

In connection with requirements, requests or orders to produce documents or information in the circumstances provided in Sections 8.03 and 9.09(a)(vi) (“Disclosure Order”) each Party shall, to the extent practicable, use reasonable efforts to (i) notify the other Party before disclosing the confidential information, and (ii) prevent or limit such disclosure. After using such reasonable efforts, the disclosing party may not be (x) prohibited from complying with a Disclosure Order, or (y) liable to the other Party for monetary or other damages incurred in connection with the disclosure of any terms or conditions of this Agreement which are the subject of such Disclosure Order.

(c)

Except as provided in clause (y) of Section 9.09(b), the Parties are entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, the confidentiality obligations set forth in this Section 9.09.

9.10

Insurance.

(a)

As of the Effective Date and throughout the Term (and for such additional periods as may be specified in this Section 9.10), Seller shall, at its own expense, provide and maintain in effect the insurance policies and minimum limits of coverage specified in this Section 9.10, and such additional coverage as may be required by Applicable Law, with insurance companies which are authorized to do business in the state in which the services are to be performed and which have an A.M. Best’s Insurance Rating of not less than A-:VII. The minimum insurance requirements specified in this Section 9.10 do not in any way limit or relieve Seller of any obligation assumed elsewhere in this Agreement, including, but not limited to, Seller’s defense and indemnity obligations.

(i)

Workers’ Compensation Insurance with the statutory limits required by the state having jurisdiction over Seller’s employees;

(ii)

Employer’s Liability Insurance with limits of not less than:

1)

Bodily injury by accident – One Million dollars ($1,000,000) each accident;

2)

Bodily injury by disease – One Million dollars ($1,000,000) policy limit; and

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3)

Bodily injury by disease – One Million dollars ($1,000,000) each employee; and

(iii)

Commercial General Liability Insurance, (which, except with the prior written consent of Buyer and subject to Sections 9.10(a)(ii)(1) and (2), shall be written on an “occurrence,” not a “claims-made” basis), covering all operations by or on behalf of Seller arising out of or connected with this Agreement, including coverage for bodily injury, broad form property damage, personal and advertising injury, products/completed operations, and contractual liability. Such insurance shall bear a combined single limit per occurrence and annual aggregate of not less than one million dollars ($1,000,000), exclusive of defense costs, for all coverages. Such insurance shall contain standard cross-liability and severability of interest provisions. If Seller elects, with Buyer’s written concurrence, to use a “claims made” form of Commercial General Liability Insurance, then the following additional requirements apply:

1) The retroactive date of the policy must be prior to the Effective Date; and 2) Either the coverage must be maintained for a period of not less than four years after the Agreement terminates, or the policy must provide for a supplemental extended reporting period of not less than four years after the Agreement terminates. (iv)

Commercial Automobile Liability Insurance covering bodily injury and property damage with a combined single limit of not less than $1,000,000 per occurrence. Such insurance shall cover liability arising out of Seller’s use of all owned (if any), non-owned and hired automobiles in the performance of the Agreement.

(v)

Umbrella/Excess Liability Insurance, written on an “occurrence,” not a “claimsmade” basis, providing coverage excess of the underlying Employer’s Liability, Commercial General Liability, and Commercial Automobile Liability insurance, on terms at least as broad as the underlying coverage, with limits of not less than $10,000,000 per occurrence and in the annual aggregate. The insurance requirements of this Section 9.10 can be provided by any combination of Seller’s primary and excess liability policies.

(b)

The insurance required in Section 9.10(a) apply as primary insurance to, without a right of contribution from, any other insurance maintained by or afforded to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, and employees, regardless of any conflicting provision in Seller's policies to the contrary. To the extent permitted by Applicable Law, Seller and its insurers are required to waive all rights of recovery from or subrogation against Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, employees and insurers. The Commercial General Liability and Umbrella/Excess Liability insurance required above shall name Buyer, its subsidiaries and affiliates, and their respective

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officers, directors, shareholders, agents and employees, as additional insureds for liability arising out of Seller’s construction, ownership or Operation of the Generating Facility. (c)

At the time this Agreement is executed, or within a reasonable time thereafter, and within a reasonable time after coverage is renewed or replaced, Seller shall furnish to Buyer certificates of insurance evidencing the coverage required in this Section 9.10, written on forms and with deductibles reasonably acceptable to Buyer. All deductibles, co-insurance and self-insured retentions applicable to the insurance above shall be paid by Seller. All certificates of insurance shall note that the insurers issuing coverage shall endeavor to provide Buyer with at least 30 days’ prior written notice in the event of cancellation of coverage. Buyer’s receipt of certificates that do not comply with the requirements stated herein, or Seller’s failure to provide certificates, does not limit or relieve Seller of the duties and responsibility of maintaining insurance in compliance with the requirements in this Section 9.10 and does not constitute a waiver of any of the requirements in this Section 9.10.

(d)

If Seller fails to comply with any of the provisions of this Section 9.10, Seller, among other things and without restricting Buyer’s remedies under the Applicable Law or otherwise, shall, at its own cost and expense, act as an insurer and provide insurance in accordance with the terms and conditions above. With respect to the required Commercial General Liability, Umbrella/Excess Liability and Commercial Automobile Liability insurance, Seller shall provide a current, full and complete defense to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, employees, assigns, and successors in interest, in response to a third party claim in the same manner that an insurer would have, had the insurance been maintained in accordance with the terms and conditions set forth above.

(e)

Seller has the right to self-insure to comply with Seller’s obligations under this Section 9.10. The insurance carrier or carriers and form of policy (including any deductible amount), or any plan for self-insurance shall be subject to review and approval by Buyer, which approval may not be unreasonably withheld, conditioned or delayed.

9.11

Nondedication. Notwithstanding any other provisions of this Agreement, neither Party dedicates any of the rights that are or may be derived from this Agreement or any part of its facilities involved in the performance of this Agreement to the public or to the service provided under this Agreement, and such service shall cease upon termination of this Agreement.

9.12

Mobile Sierra. Notwithstanding any provision of this Agreement, neither Party will seek, nor will they support any third party in seeking, to prospectively or

Article Nine

Miscellaneous

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

retroactively revise the rates, terms, or conditions of service of this Agreement through application or complaint to FERC pursuant to the provisions of Section 205, 206, or 306 of the Federal Power Act, or any other provisions of the Federal Power Act, absent prior written agreement of the Parties. Further, absent the prior agreement in writing by both Parties, the standard of review for changes to the rates, terms or conditions of service of this Agreement proposed by a Party, a non-Party or the FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 US 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 US 348 (1956). 9.13

Seller Ownership and Control of Generating Facility. Seller agrees, that, in accordance with FERC Order No. 697, upon request of Buyer, Seller shall submit a letter of concurrence in support of an affirmative statement by Buyer that the contractual arrangement set forth in this Agreement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR Section 35.42. Seller also agrees that it will not, in filings, if any, made subject to Order Nos. 652 and 697, claim that the contractual arrangement set forth in this Agreement conveys ownership or control of generation capacity from Seller to Buyer.

9.14

Simple Interest Payments. Except as specifically provided in this Agreement, any outstanding and past due amounts owing and unpaid by either Party under the terms of this Agreement shall be eligible to receive a Simple Interest Payment calculated using the Interest Rate for the number of days between the date due and the date paid.

9.15

Payments. Payments to be made under this Agreement shall be made, at Seller’s option, by check or electronic wire funds transfer.

9.16

Provisional Relief. The Parties acknowledge and agree that irreparable damage would occur if certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or the other security, to seek a preliminary injunction, temporary restraining order, or other provisional relief as a remedy for a breach of Sections 3.01, 3.02, 3.03, or 9.09 in any court of competent jurisdiction, notwithstanding the obligation to submit all other disputes (including all Claims for monetary damages under this Agreement) to arbitration pursuant to Section 10.01. The Parties further acknowledge and agree that the results of such arbitration may be rendered ineffectual without such provisional relief.

Article Nine

Miscellaneous

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Such a request for provisional relief does not waive a Party’s right to seek other remedies for the breach of the provisions specified above in accordance with Section 10.01, notwithstanding any prohibition against claim-splitting or other similar doctrine. The other remedies that may be sought include specific performance and injunctive or other equitable relief, plus any other remedy specified in this Agreement for such breach of the provision, or if this Agreement does not specify a remedy for such breach, all other remedies available at law or equity to the Parties for such breach. *** End of Article Nine ***

Article Nine

Miscellaneous

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

ARTICLE TEN.

DISPUTE RESOLUTION

10.01 Dispute Resolution. Other than requests for provisional relief under Section 9.16, any and all disputes, Claims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which Disputes the Parties have been unable to resolve by informal methods, will first be submitted to mediation in accordance with the procedures described in Section 10.02, and if the Dispute is not resolved through mediation, then for final and binding arbitration in accordance with the procedures described in Section 10.03. 10.02 Mediation. Either Party may initiate mediation by providing Notice to the other Party of a written request for mediation, setting forth a description of the Dispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the panel of neutrals from JAMS or any other mutually acceptable non-JAMS Mediator, and in scheduling the time and place of the mediation. Such selection and scheduling will be completed within 45 days after Notice of the request for mediation. Unless otherwise agreed to by the Parties, the mediation will not be scheduled for a date that is greater than 120 days from the date of Notice of the request for mediation. The Parties covenant that they will participate in the mediation, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and costs will be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, will not be subject to discovery and will be confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them; provided, however, that evidence that is otherwise admissible or discoverable will not be rendered inadmissible or non-discoverable as a result of its use in the mediation. 10.03 Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation in accordance with Section 10.02 by providing Notice of a demand for binding arbitration before a single, neutral arbitrator (the “Arbitrator”) at any time following the unsuccessful conclusion of the mediation provided for in Section 10.02.

Article Ten

Dispute Resolution

Page 61

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

The Parties will cooperate with one another in selecting the Arbitrator within 60 days after Notice of the demand for arbitration and will further cooperate in scheduling the arbitration to commence no later than 180 days from the date of Notice of the demand. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator will be appointed as provided for in California Code of Civil Procedure Section 1281.6. To be qualified as an Arbitrator, each candidate must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator will be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon Notice of a Party’s demand for binding arbitration, such Dispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, will be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regard to principles of conflicts of laws. Except as provided for in this Section 10.03, the arbitration will be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated. Absent the existence of such rules and procedures, the arbitration will be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration will be in [____]Los Angeles, California, and discovery will be limited as follows: {Buyer Comment: For PG&E, insert San Francisco; for SDG&E, insert San Diego; and for SCE, insert Los Angeles.}

(a)

Before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment);

(b)

The initial disclosure will occur within 30 days after the initial conference with the Arbitrator or at such time as the Arbitrator may order;

(c)

Discovery may commence at any time after the Parties’ initial disclosure;

Article Ten

Dispute Resolution

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Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(d)

The Parties will not be permitted to propound any interrogatories or requests for admissions;

(e)

Discovery will be limited to 25 document requests (with no subparts), three lay witness depositions, and three expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents);

(f)

Each Party is allowed a maximum of three expert witnesses, excluding rebuttal experts;

(g)

Within 60 days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding;

(h)

Within 30 days after the initial expert disclosure, the Parties may designate a maximum of two rebuttal experts;

(i)

Unless the Parties agree otherwise, all direct testimony will be in form of affidavits or declarations under penalty of perjury; and

(j)

Each Party shall make available for cross-examination at the arbitration hearing its witnesses whose direct testimony has been so submitted.

Subject to Article Seven, the Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections 3.01, 3.02, 3.03 or 9.09. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator must, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs will be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail.

Article Ten

Dispute Resolution

Page 63

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Until such award is made, however, the Parties will share equally in paying the costs of the arbitration. *** End of Article Ten ***

Article Ten

Dispute Resolution

Page 64

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed by their respective authorized representatives as of the Effective Date.

[SELLER’S NAME]KERN RIVER COGENERATION COMPANY,

[BUYER’S NAME]SOUTHERN CALIFORNIA EDISON COMPANY,

a [Seller’s business registration] California general partnership

a California corporation

By:_____________________________ Name:________________________ Neil Burgess Title:_________________________ Executive Director

By:_____________________________ Name:________________________ Marc Ulrich Title:_________________________ Vice President, Renewable and Alternative Power

Signatures

Page 65

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT A Definitions For purposes of this Agreement, the following terms and variations thereof have the meanings specified or referred to in this Exhibit A: “Actual HR” means the Heat Rate that must be used in accordance with and subject to the terms set forth in Section 2(a)(ii) of Exhibit S, which Heat Rate Buyer shall calculate, on the date of the commencement of the First Compliance Period, using the following formula: Actual HRn = The average of the Daily HRn for each delivery or flow date in the two (2) year period immediately preceding the commencement of the First Compliance Period Where: Daily HRn = [EPn – VOMn] / [GPn + GTn] Where: EPn = The average of the Day-Ahead hourly electric energy prices, as determined by the Integrated Forward Market (as defined in the CAISO Tariff) for (i) SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor, if Buyer is SCE or SDG&E, and (ii) NP15 Existing Zone Generation Trading Hub (formerly known as NP15), or its successor, if Buyer is PG&E; VOMn = Calendar month avoided variable O&M for the applicable month ($/kWh), per the Decision and CPUC Resolution E-4246; GPn = The applicable daily gas price index, which is (i) Platt’s Gas Daily (currently SoCalGas gas indices), if Buyer is SCE or SDG&E, or (ii) Platt’s Gas Daily (currently SoCalGas and PG&E Malin gas indices), if Buyer is PG&E; and GTn = The gas transportation rate for the applicable month, per CPUC Resolution E-4246. “Additional GHG Documentation” means the documentation necessary to allocate Free Allowances to electric energy delivered by Seller to Buyer, which documentation consists of the following, in each case for the time-period to which the Free Allowances are to apply: (a) the total amount of GHG emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, the Useful Thermal Energy Output of the Generating Facility, and the electric energy delivered to Buyer; (b) the Useful Thermal Energy Output of the Generating Facility; (c) the total electric energy produced by the Generating Facility, the electric energy

Exhibit A

Definitions

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

used to the serve the Site Host Load, and the electric energy delivered to Buyer; and (d) total fuel usage of the Generating Facility. “Agreement” has the meaning set forth in the Preamble. “Allowance” means a limited tradable authorization (whether in the form of a credit, allowance or other similar right), allocated to, issued to or purchased by, Seller, the Site Host or ana Related Entity of Seller, with respect to the Generating Facility, to emit one MT of Greenhouse Gas, in accordance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), and as applied to the Greenhouse Gas emitted by the Generating Facility. “Allowance Cost” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “Allowed Firm Energy” is determined in Section 3(l) of Exhibit D. “Allowed Hourly Energy”, or “E”, is determined in Section 3(f) of Exhibit D. “Allowed Payment Energy”, or “APE”, is determined in Section 2(c) of Exhibit D. “Ambient Outage” means reductions in capacity due to that status of, or variations in, Site Host Load or ambient weather conditions. “Annual GHG Reports” has the meaning set forth in Section 3(a) of Exhibit S. “Applicable HR” has the meaning set forth in Section 1 of Exhibit S. “Applicable Laws” means all constitutions, treaties, laws, ordinances, rules, regulations, interpretations, permits, judgments, decrees, injunctions, writs and orders of any Governmental Authority or arbitrator that apply to either or both of the Parties, the Generating Facility or the terms of this Agreement. “Arbitrator” has the meaning set forth in Section 10.03. “As-Available Capacity”, or “AAC”, is determined in Section 3(c) of Exhibit D. “As-Available Capacity Payment”, or “ACP”, is determined in Section 3(b) of Exhibit D. “As-Available Capacity Price” means the price adopted by the CPUC in the Decision and in subsequent rulings of the CPUC implementing the Decision, or pursuant to any such other formula as the CPUC may adopt from time to time for As-Available Capacity Payments to be made to Buyer’s Qualifying Cogeneration Facilities for the applicable year, as set forth in Section 3(b) of Exhibit D, in dollars per kW-year.

Exhibit A

Definitions

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“As-Available Contract Capacity” means the electric energy generating capacity that Seller provides on an as-available basis for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). “Availability Credit Factor”, or “ACF”, is determined in Section 3(i) of Exhibit D. “Availability Incentive Payments” has the meaning set forth in the CAISO Tariff. “Availability Penalty Factor”, or “APF”, is determined in Section 3(n) of Exhibit D. “Availability Standards” has the meaning set forth in the CAISO Tariff. “Bankrupt” means with respect to any Person, such Person: (a) Files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it (which petition is not dismissed within 90 days); (b) Makes an assignment or any general arrangement for the benefit of creditors; (c) Otherwise becomes bankrupt or insolvent (however evidenced); (d) Has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets; or (e) Is generally unable to pay its debts as they fall due. “Benchmark Capacity” is determined, as applicable, in Section 3(a) of Exhibit D-1, Section 3(a) of Exhibit D-2, and Section 9(a) of Exhibit E. “Burner Tip Gas Price” or “BTGP” has the meaning set forth in Section 1 of Exhibit S. “Business Day” means any day except a Saturday, Sunday, the Friday after the United States Thanksgiving holiday, or a Federal Reserve Bank holiday that begins at 8:00 a.m. and end at 5:00 p.m. local time for the Party sending a Notice or payment or performing a specified action. “Buyer” has the meaning set forth in the Preamble. “Buyer Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy produced by the Generating Facility.

Exhibit A

Definitions

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Buyer Parent Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy delivered to the CAISO for the CAISO Global Resource ID associated with the Generating Facility. “Buyer Projected Energy Forecast” has the meaning set forth in Section 2(a) of Exhibit G. “CAISO” means the California Independent System Operator Corporation or successor entity that dispatches certain generating units, supplies certain loads and controls the transmission facilities of entities that (a) own, operate and maintain transmission lines and associated facilities or have entitlements to use certain transmission lines and associated facilities, and (b) have transferred to the CAISO or its successor entity operational control of such facilities or entitlements. “CAISO-Approved Meter” means any revenue quality, electric energy measurement meter furnished by Seller, that (a) is designed, manufactured and installed in accordance with the CAISO’s metering requirements, or, to the extent that the CAISO’s metering requirements do not apply, Prudent Electrical Practices, and (b) includes all of the associated metering transformers and related appurtenances that are required in order to measure the net electric energy output from the Generating Facility. “CAISO-Approved Quantity” means the total quantity of electric energy that Buyer Schedules with the CAISO and the CAISO approves in its final schedule which is published in accordance with the CAISO Tariff. “CAISO Charges” means the debits, costs, fees, penalties, sanctions, interest or similar charges, including imbalance energy charges, that are directly assigned by the CAISO to the CAISO Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement. “CAISO Charges Invoice” has the meaning set forth in Section 5 of Exhibit G. “CAISO Controlled Grid” has the meaning set forth in the CAISO Tariff. “CAISO Forced Outage Report” means a complete copy of a forced outage report in a form reasonably acceptable to Buyer which includes detailed information regarding the event, including the affected Generating Unit, outage start date and time, estimation of outage duration, MW unavailable and summary of work to be performed. “CAISO Global Resource ID” means the number or name assigned by the CAISO to the CAISOApproved Meter. “CAISO Revenues” means the credits, fees, payments, revenues, interest or similar benefits, including imbalance energy payments, that are directly assigned by the CAISO to the CAISO

Exhibit A

Definitions

Page 4

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement. “CAISO Tariff” means the California Independent System Operator Corporation Operating Agreement and Tariff, including the rules, protocols, procedures and standards attached thereto, as the same may be amended or modified from time to time and approved by the FERC. “Capacity Attributes” means any and all current or future defined characteristics, certificates, tag, credits, ancillary service attributes, or accounting constructs, howsoever entitled, other than Resource Adequacy Benefits, attributed to or associated with the electricity generating capability of the Generating Facility. “Capacity Credit Hours”, or “CCH”, is determined in Section 3(m) of Exhibit D. “Capacity Credit Period” is determined in Section 3(b)(iv) of Exhibit E. “Capacity Payment Allocation Factors”, or “CAF”, means the TOD Period factors which are used to calculate the TOD Period Capacity Payment, as set forth in the table in Section 3(a) of Exhibit D. “Capacity Performance Requirement”, or “CR”, means the values set forth in Section 1.04. “CARB” means California Air Resources Board, or any successor entity. “CARB Annual Report” has the meaning set forth in Section 3(a)(i) of Exhibit S. “CARB Mandatory GHG Emissions Annual Report” means the mandatory reporting regulations approved by CARB in December 2007, which became effective in January 2009, pursuant to the requirements set forth in the California Global Warming Solutions Act of 2006 for the reporting of Greenhouse Gas by major sources. “CEC” means the California Energy Commission, or any successor entity. “CFR” means the Code of Federal Regulations, as may be amended from time to time. “Check Meter” means the Buyer revenue-quality meter section or meter(s), which Buyer may require at its discretion, as set forth in Section 3.08(b) and will include those devices normally supplied by Buyer or Seller under the applicable utility Electric Service Requirements. “Claiming Party” has the meaning set forth in Section 5.02. “Claims” means all third party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys’ fees and court costs, whether

Exhibit A

Definitions

Page 5

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

incurred by settlement or otherwise, and whether such claims or actions are threatened or filed before or after the termination of this Agreement. “Collateral Assignment Agreement” has the meaning set forth in Section 9.05. “Confidential Information” means all oral or written communications exchanged between the Parties on or after the Effective Date relating to the implementation of this Agreement, including information related to Seller’s compliance with operating and efficiency standards applicable to a “qualifying cogeneration facility” (as contemplated in 18 CFR Part 292, Section 292.205). Confidential Information does not include (i) information which is in the public domain as of the Effective Date or which comes into the public domain after the Effective Date from a source other than from the other Party, (ii) information which either Party can demonstrate in writing was already known to such Party on a non-confidential basis before the Effective Date, (iii) information which comes to a Party from a bona fide third-party source not under an obligation of confidentiality, or (iv) information which is independently developed by a Party without use of or reference to Confidential Information or information containing Confidential Information. “Control Area” means the electric power system (or combination of electric power systems) under the operational control of the CAISO or any other electric power system under the operational control of another organization vested with authority comparable to that of the CAISO. “Converted Physical Trade”, or “CPT”, means the quantity from Physical Trades, in MWh, that did not pass CAISO’s physical validation of the IFM. “Converted Physical Trade Price” means the price, in dollars per MWh, used by the CAISO to settle the quantity, in MWh, associated with the Converted Physical Trade. “Costs” means, with respect to the Non-Defaulting Party, brokerage fees, commissions, legal expenses and other similar third party transaction costs and expenses reasonably incurred by such Party in entering into any new arrangement which replaces this Agreement. “CPUC” means the California Public Utilities Commission, or any successor entity. “CPUC Approval” means a final and non-appealable order of the CPUC, without conditions or

modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement. CPUC Approval will be deemed to have occurred on the

Exhibit A

Definitions

Page 6

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. “Curtailment Period” means a time period for which Seller is requested by CAISO or a Transmission Provider to curtail its Power Product for Force Majeure or otherwise. “D.” has the meaning set forth in Recital A. “Day-Ahead” has the meaning set forth in the CAISO Tariff. “Day-Ahead Market” has the meaning set forth in the CAISO Tariff. “Day-Ahead Price” means the LMPQF, as set forth in Section 1 of Exhibit S. “Day-Ahead Schedule” has the meaning set forth in the CAISO Tariff. “Decision” has the meaning set forth in Recital A. “Defaulting Party” has the meaning set forth in Section 6.01(a). “Delivery Point” has the meaning set forth in Section 1.03. “Disclosure Order” has the meaning set forth in Section 9.09(b). “Dispute” has the meaning set forth in Section 10.01. “Early Termination Date” has the meaning set forth in Section 6.02(a). “Earned Capacity Hours”, or “ECH”, means the number of firm capacity equivalent available hours determined by dividing the Firm TOD Energy by the Firm Contract Capacity, as set forth in Section 3(j) of Exhibit D. “Effective Date” has the meaning set forth in the Preamble. “Emergency Condition” has the meaning set forth in the Transmission Provider’s LGIA or SGIA with Seller, or the distribution-level FERC-jurisdictional interconnection agreement with Seller, as applicable; provided, however, that if Seller interconnects pursuant to Tariff Rule 21, “Emergency Condition” means “Emergency”, as defined in such Tariff Rule 21. “Equitable Defense” means any Bankruptcy or other laws affecting creditors’ rights generally, and with regard to equitable remedies, the discretion of the court before which proceedings to obtain same may be pending. “Equity Investment” means an acquisition by a Lender of an ownership interest in the form of stock, membership or partnership interest of Seller or the immediate parent of Seller under which Exhibit A

Definitions

Page 7

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Seller retains the right to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s rights to enforce its ownership interest in Seller or the immediate parent of Seller, as applicable, in the event of a default by Seller or the immediate parent of Seller under Lender’s equity acquisition agreement or the partnership agreement, operating agreement, or other agreement governing the relationship between the equity owners of the Generating Facility. “Event of Default” has the meaning set forth in Section 6.01. “Existing PPA” has the meaning set forth in Section 1.01. “Existing Qualifying Cogeneration Facility” means a Generating Facility that commenced Parallel Operation before the Settlement Effective Date, and that, as of the Settlement Effective Date, (a) is a Qualifying Cogeneration Facility, and (b) is the generating facility under the Existing PPA. “Expected Term Year Energy Production” means the Metered Energy quantity expected to be produced by the Generating Facility during each Term Year, as set forth in Section 1.02(e). “Federal Funds Effective Rate” means the rate for that day opposite the caption “Federal Funds (effective)” as set forth in the weekly statistical release as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System. “FERC” means the Federal Energy Regulatory Commission, or any successor entity. “FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.05 in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. “Financial Consolidation Requirement” has the meaning set forth in Section 3.20(a). “Financial Incentives” means any and all financial incentives, benefits or credits associated with the Generating Facility, or the ownership or Operation thereof, or the electrical or thermal output of the Generating Facility, including any production or investment tax credits, real or personal

Exhibit A

Definitions

Page 8

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

property tax credits or sales or use tax credits, but not including any Green Attributes, Capacity Attributes or Resource Adequacy Benefits. “Firm Capacity Payment”, or “FCP”, has the meaning set forth in Section 3(g) of Exhibit D. “Firm Capacity Price” or “CP” is set forth in Section 1.06(a), in dollars per kW-year. “Firm Contract Capacity”, or “FCC”, means the monthly generating capacity that Seller commits to have available at the Site for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). “Firm TOD Energy”, or “FE”, has the meaning set forth in Section 3(k) of Exhibit D. “First Compliance Period” means the first period of time for compliance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation). There will be no more than a single First Compliance Period. “First Penalty Month” has the meaning set forth in Section 3(b) of Exhibit I. “Floor Test Term” means the date that the First Compliance Period commences, for a period of three years. “Forced Outage” has the meaning set forth in the CAISO Tariff. “Force Majeure” means any event or circumstance to the extent beyond the control of, and not the result of the negligence of, or caused by, the Party seeking to have its performance obligation excused thereby, which by the exercise of due diligence such Party could not reasonably have been expected to avoid and which by exercise of due diligence it has been unable to overcome. Force Majeure does not include: (a) A failure of performance of any other Person, including any Person providing electric transmission service or fuel transportation to the Generating Facility, except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure event; (b) Failure to timely apply for or obtain Permits or other credits required to Operate the Generating Facility; (c) Breakage or malfunction of equipment (except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure); or (d) A lack of fuel of an inherently intermittent nature such as wind, water, solar radiation or waste gas or waste derived fuel.

Exhibit A

Definitions

Page 9

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Force Majeure Credit Value”, or “FCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Force Majeure curtailment requested by Buyer, determined in accordance with Section 3 of Exhibit D-1. “Forecast” means the hourly forecast of (a) the total electric energy production of the Generating Facility (in MWh) when the Generating Facility is not PIRP-eligible or Buyer is not Scheduling Coordinator net of the Site Host Load and Station Use, or (b) the available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator net of the Site Host Load and Station Use. “Forward Settlement Amount” means the Non-Defaulting Party’s Costs and Losses on the one hand, netted against its Gains, on the other. If the Non-Defaulting Party’s Gains exceed its Costs and Losses, then the Forward Settlement Amount shall be zero dollars. If the Non-Defaulting Party’s Costs and Losses exceed its Gains, then the Forward Settlement Amount shall be an amount owing to the Non-Defaulting Party. The Forward Settlement Amount does not include consequential, incidental, punitive, exemplary or indirect or business interruption damages. “Free Allowance” means any Allowance freely allocated to Seller or the Generating Facility by CARB or an authorized Governmental Authority (or any entity authorized by such Governmental Authority). “Free Allowance Notice” means the Notice, delivered by Seller to Buyer in accordance with this Agreement, that sets forth the aggregate quantity of Free Allowances received by Seller during the applicable time-period and sets forth the allocation of such Free Allowances in accordance with the following: (i)

The allocation of Free Allowances by the CARB (or any other Governmental Authority) to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable time-period; or

(ii)

If the CARB (or any other Governmental Authority) does not allocate Free Allowances received by Seller as described in subsection (i) above, then Seller shall set forth in the Free Allowance Notice the quantity of Free Allowances allocated to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable timeperiod (FAd) utilizing the following formula: FAd = FAt * [Ge/(Ge+ Gt)] * [Ed/(Esh + Ed)] Where: FAt = Total number of Free Allowances received by Seller with respect to the Generating Facility for the applicable time-period;

Exhibit A

Definitions

Page 10

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Ge (in MTs) = Emissions of Greenhouse Gas attributed to the total amount of electric energy produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Gt (in MTs) = Emissions of Greenhouse Gas attributed to the Useful Thermal Energy Output produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Ed (in kWh) = Electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period; and Esh (in kWh) = Electric energy generated by the Generating Facility and used to serve the Site Host Load for the applicable time-period; or (iii)

If the CARB (or any other Governmental Authority) does not allocate the Free Allowances received by Seller, as described in (i) above, and there is no available formula in any applicable rule or regulation for the calculation of Ge and Gt, as described in (ii) above, then Seller shall include in the Free Allowance Notice the total amount of emissions of Greenhouse Gas attributed to the electric energy period (Ge, in MTs) and the Useful Thermal Energy Output (Gt, in MTs) produced by the Generating Facility for the applicable time-period based on the two following formulas: Ge = G * (Useful Power Output / (Useful Power Output + Useful Thermal Energy Output)) Gt = G * (Useful Thermal Energy Output / (Useful Power Output + Useful Thermal Energy Output)) Where: G (in MTs) = Total emissions of Greenhouse Gas produced by the Generating Facility for the applicable time-period; Useful Power Output (in MMBtu) = As defined in 18 CFR §292.202(g), or any successor thereto;

Exhibit A

Definitions

Page 11

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Useful Thermal Energy Output (in MMBtu) = As defined in 18 CFR §292.202(h), or any successor thereto; Upon determining Ge and Gt in subsection (iii) above, Seller shall then calculate for and provide the quantity of Free Allowances attributed to electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period (FAd) using the formula set forth in subsection (ii) of this definition. “GAAP” means generally accepted accounting principles for financial reporting in the United States, consistently applied. “Gains” means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), as of the Early Termination Date resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the gain of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remaining Term and shall include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the gain of economic benefits, then the NonDefaulting Party may use information available to it internally. “Generating Facility” means the Generating Unit(s) comprising Seller’s power plant, as more particularly described in Section 1.02 and Exhibit B, including all other materials, equipment, systems, structures, features and improvements necessary for these Generating Units to produce electric energy and thermal energy, excluding the Site, land rights and interests in land. “Generating Unit” means one or more generating equipment combinations typically consisting of prime mover(s), electric generator(s), electric transformer(s), steam generator(s) and air emission control devices. The references to the term Generating Unit shall be applicable only to Generating Unit #2 and Generating Unit #4 throughout the Term. Exhibit A

Definitions

Page 12

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Generating Unit #2” means the Generating Unit described in Section 1(a) of Exhibit B of this Agreement. “Generating Unit #4” means the Generating Unit described in Section 1(b) of Exhibit B of this Agreement. “Generation Operations Center” means the location of Buyer’s real-time operations personnel. “Generator Operator” means the Person that Operates the Generating Facility and performs the functions of supplying electric energy and interconnected operations services within the meaning of the NERC Reliability Standards. “Generator Operator Obligations” means the obligations of a Generator Operator as set forth in all applicable NERC Reliability Standards. “Generator Owner” means the Person that owns the Generating Facility and has registered with the NERC as the Person responsible for complying with all NERC Reliability Standards applicable to the owner of the Generating Facility. “Generator Owner Obligations” means the obligations of a Generator Owner as set forth in all applicable NERC Reliability Standards. “GHG Allowance Price” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “GHG Auction” means any auction or other sale-by-bid event applicable to California and by an authorized Governmental Authority (or any entity authorized by such Governmental Authority) for the sale of Allowances. “GHG Charges” has the meaning set forth in Section 1 of Exhibit S. “GHG Compliance Costs” means the cost of Allowances, as determined in accordance with Exhibit S. “GHG Floor Test” has the meaning set forth in Section 2(a) of Exhibit S. “Governmental Authority” means (a) any federal, state, local, municipal or other government, (b) any governmental, regulatory or administrative agency, commission, or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power, or (c) any court or governmental tribunal. “Governmental Charges” has the meaning as set forth in Section 8.02. “Green Attributes” means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided

Exhibit A

Definitions

Page 13

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1

(3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel

1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program.

Exhibit A

Definitions

Page 14

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. “Greenhouse Gas” or “GHG” means emissions released into the atmosphere of carbon dioxide (CO2), nitrous oxide (N2O) and methane (CH4), which are produced as the result of combustion or transport of fossil fuels. Other greenhouse gases may include hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6), which are generated in a variety of industrial processes. Greenhouse gases may be defined or expressed in terms of a MT of CO2equivalent, in order to allow comparison between the different effects of gases on the environment; provided, however, that the definition of the term “Greenhouse Gas”, as set forth in the immediately preceding sentence, shall be deemed revised to include any update or other change to such term by the CARB or any other Governmental Authority. “Heat Rate” means, for purposes of this Agreement, the value obtained, in BTU per kWh, when the fuel input, on a Higher Heating Value basis, in BTU is divided by generation, net of Station Use, in kWh. “Higher Heating Value” means the high or gross heat content of the fuel with the heat of vaporization included (the water vapor is assumed to be in a liquid state). “Host Site” means the site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Related Entities located at such site. “Hour-Ahead Scheduling Deadline” means 30 minutes before the deadline established by the CAISO for the submission of schedules for the applicable hour. “Hourly Credit Value” is determined, as applicable, in Section 3(b) of Exhibit D-1, Section 3(b) of Exhibit D-2 and Section 9(b)(i) of Exhibit E. “Hourly Debit Value” is determined in Section 9(b)(ii) of Exhibit E. “Hourly Location Adjustment”, or “LA”, has the meaning set forth in Section 1 of Exhibit S. “Hourly Power Output” means an hourly rate of electric energy delivery, in kWh per hour, that is equal to the Metered Energy for one hour, in kWh, divided by one hour. “IFM” (i.e., the Integrated Forward Market) has the meaning set forth in the CAISO Tariff. “IFM Load Uplift Obligation” means the obligation of a Scheduling Coordinator to pay its share of unrecovered IFM Bid Costs (as defined in the CAISO Tariff) paid to resources through Bid Cost Recovery (as defined in the CAISO Tariff). “IFRS” has the meaning set forth in Section 3.20(b)(iii).

Exhibit A

Definitions

Page 15

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Incipient Event of Default” has the meaning set forth in Section 9.05(a). “Interconnection Study” means a study prepared by or on behalf of the Transmission Provider or the CAISO to evaluate the impact of the interconnection of the Generating Facility to the Transmission Provider’s electric system or the applicable Control Area operator’s electric grid. “Interest Rate” means an annual rate equal to the rate published in The Wall Street Journal as the “Prime Rate” (or, if more than one rate is published, the arithmetic mean of such rates) as of the date payment is due plus two percentage points; provided, however, that in no event shall the Interest Rate exceed the maximum interest rate permitted by Applicable Laws. “Inter-SC Trade” means a trade between Scheduling Coordinators of electric energy, Ancillary Service (as defined in the CAISO Tariff), or IFM Load Uplift Obligation in accordance with the CAISO Tariff. “JAMS” means the Judicial Arbitration and Mediation Services, Inc. or any successor entity. “kW” means a kilowatt (1,000 watts) of electric capacity or power output. “kWh” means a kilowatt-hour (1,000 watt-hours) of electric energy. “LAR” means local area reliability, which is any program of localized resource adequacy requirements established for jurisdictional load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by another Local Regulatory Authority having jurisdiction over the load serving entity. LAR may also be known as local resource adequacy, local RAR, or local capacity requirement in other regulatory proceedings or legislative actions. “LAR Showings” means the LAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction over the load serving entity. “Lease” means one or more agreements whereby Seller leases the Site(s) described in Section 1.02 and Exhibit B from a third party, the term of which lease begins on or before the Term Start Date and extends at least through the Term End Date. “Lender” means any third-party institution or entity or successor in interest or assignees that either (i) purchases the Generating Facility and then leases it to Seller under a Sale-Leaseback Transaction, or (ii) provides development, bridge, construction, or permanent debt or tax equity financing or refinancing (including an Equity Investment) for the Generating Facility to Seller or credit support in connection with this Agreement. “LGIA” (i.e., Large Generator Interconnection Agreement or Standard Large Generator Interconnection Agreement) has the meaning set forth in the CAISO Tariff. Exhibit A

Definitions

Page 16

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Limited TOD Energy”, or “LE”, has the meaning set forth in Section 3(e) of Exhibit D. “LMPQF” has the meaning set forth in Section 1 of Exhibit S. “LMPTrading Hub” has meaning set forth in Section 1 of Exhibit S. “Local Regulatory Authority” has the meaning set forth in the CAISO Tariff. “Locational Marginal Price” has the meaning set forth in the CAISO Tariff. “Losses” means, with respect to any Party, an amount equal to the present value of the economic loss to it if any (exclusive of Costs), as of the Early Termination Date, resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the loss of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remainder of the Term and must include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the loss of economic benefits, then the Non-Defaulting Party may use information available to it internally. “MAEm” has the meaning set forth in Section 3(a) of Exhibit I. “MAE Failure” has the meaning set forth in Section 3(b) of Exhibit I. “Maintenance Credit Value”, or “MCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Maintenance Outage or a Major Overhaul which has been properly scheduled in accordance with Exhibit E. “Maintenance Debit Value” is a value indicating how much allowance is used when Seller requests credit for a Maintenance Outage or a Major Overhaul in accordance with Exhibit E.

Exhibit A

Definitions

Page 17

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Maintenance Outage” means a time period during which Seller plans to reduce the Power Output of the Power Product, in full or in part, in order to facilitate maintenance work on the Generating Facility, other than a Major Overhaul. “Major Overhaul” means a time period during which Seller plans to remove the Generating Facility from Operation in order to dismantle the Generating Facility’s equipment for inspections, repairs or replacement, with the goal that such equipment will be reassembled and made available for Operation. “Major Overhaul Allowance” is a value indicating a Term-Year maximum allowance with which Seller can request credit for a Major Overhaul in accordance with Exhibit E. “Market Disruption Event” means, with respect to any MHR Source, any of the following events: (i) the permanent discontinuation or material suspension of trading in the exchange or in the market specified for determining a Market Heat Rate; (ii) the temporary or permanent discontinuance or unavailability of the MHR Source; or (iii) the temporary or permanent closing of any exchange specified for determining a Market Heat Rate. For purposes of this definition, “temporary” means five (5) or more continuous Trading Days. “Market Heat Rate” means the 12-month forward market heat rate, calculated for each calendar pricing month utilizing the methodology set forth in Commission Decision 07-09-040 and Commission Resolution E-4246 for [For SCE and SDG&E: SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor] [For PG&E: NP15 Existing Zone Generation Trading Hub (formerly known as NP15), or its successor]. Unless otherwise agreed to by the Parties, this definition of Market Heat Rate will not be updated by any subsequent decision, ruling or order by the CPUC. “Maximum Allowed Capacity”, or “MAC”, is determined in Section 3(d) of Exhibit D. “Maximum Firm Capacity Payment”, or “MFCP”, means the maximum payment that Seller can earn during a year for the delivery of Firm Contract Capacity that is calculated in accordance with the procedure set forth in Section 3(h) of Exhibit D. “Mediator” has the meaning set forth in Section 10.02. “Metered Amounts” means the quantity of electric energy, expressed in kWh, as recorded by (i) the CAISO-Approved Meter(s), which quantity may include compensation factors introduced by the CAISO into the CAISO-Approved Meter(s), or (ii) Check Meter(s), as applicable. “Metered Energy” means the quantity of electric energy, expressed in kWh, as measured by (i) the CAISO-Approved Meter(s), which quantity will be adjusted so as not to include compensation factors, if any, introduced by the CAISO into the CAISO-Approved Meter(s) other than (x) electric energy consumed within the generator collection system as losses between the

Exhibit A

Definitions

Page 18

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

generator(s) and the high voltage side of the Generating Facility output transformer(s) and, (y) if applicable, the Generating Facility’s radial line losses, or (ii) Check Meters, as applicable, in each case for the specified Metering Interval. “Metering Interval” means the smallest measurement time period over which data are recorded by the CAISO-Approved Meters or Check Meters. “MHR Source” the relevant publications used to determine the Market Heat Rate. “Monthly Contract Payment” has the meaning set forth in Section 4.01. “Monthly Scheduling Fee” is described in Section 4(b) of Exhibit G. “MT” means metric ton(s). “MW” means a megawatt (1,000,000 watts) of electric capacity or power output. “MWh” means a megawatt-hour (1,000,000 watt-hours) of electric energy or power output. “NERC” means the North American Electric Reliability Corporation, or any successor entity. “NERC Reliability Standards” means the most recent version of those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by the NERC and approved by the applicable regulatory authorities, which are available at http://www.nerc.com/files/Reliability_Standards_Complete_Set.pdf, or any successor thereto. “NERC Standards Non-Compliance Penalties” means any and all monetary fines, penalties, damages, interest or assessments by the NERC, the CAISO, the WECC, a Governmental Authority or any Person acting at the direction of a Governmental Authority arising from or relating to a failure to perform the obligations of Generator Operator or Generator Owner as set forth in the NERC Reliability Standards. “Net Contract Capacity”, or “NCC”, means the sum of Firm Contract Capacity and As-Available Contract Capacity, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). Net Contract Capacity may not exceed PMax. “Net Qualifying Capacity” has the meaning set forth in the CAISO Tariff. “Non-Availability Charges” has the meaning set forth in the CAISO Tariff. “Non-Defaulting Party” has the meaning set forth in Section 6.02.

Exhibit A

Definitions

Page 19

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Notice” means notices, requests, statements or payments provided in accordance with Section 9.07 and Exhibit N. “OMAR” means the Operational Metering Analysis and Reporting System operated and maintained by the CAISO as the repository of settlement quality meter data, or any successor thereto. “Operate,” “Operating,” or “Operation” means to provide (or the provision of) all the operation, engineering, purchasing, repair, supervision, training, inspection, testing, protection, use management, improvement, replacement, refurbishment, retirement, and maintenance activities associated with operating the Generating Facility in order to produce the Power Product in accordance with Prudent Electrical Practices. “Outage” has the meaning set forth in the CAISO Tariff. “Outage Schedule” has the meaning set forth in Section 2(a) of Exhibit R. “Outage Schedule Submittal Requirements” describes the obligations of Seller to submit maintenance and planned outage schedules (as defined in the CAISO Tariff under WECC rules) to Buyer 24 months in advance, as set forth in Exhibit R. “Parallel Operation” means the Generating Facility’s electrical apparatus is connected to the Transmission Provider’s system and the circuit breaker at the point of common coupling is closed. The Generating Facility may be producing electric energy or consuming electric energy at such time. “Party” has the meaning set forth in the Preamble. “Peak Months” means [___]June, July, August and September. {Buyer Comment: For SCE and PG&E, the Peak Months are June, July, August and September. For SDG&E, the Peak Months are May, June, July, August and September.}

“Penalized As-Available Contract Capacity” has the meaning set forth in Section 3(b)(ii) of Exhibit I. “Penalized Firm Contract Capacity” has the meaning set forth in Section 3(b)(i) of Exhibit I. “Performance Tolerance Band Lower Limit” is determined in Section 1 of Exhibit K. “Performance Tolerance Band Upper Limit” is determined in Section 1 of Exhibit K. “Permits” means all applications, approvals, authorizations, consents, filings, licenses, orders, permits or similar requirements imposed by any Governmental Authority, or the CAISO, in order

Exhibit A

Definitions

Page 20

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

to develop, construct, Operate, maintain, improve, refurbish or retire the Generating Facility or to Forecast or deliver the electric energy produced by the Generating Facility to Buyer. “Person” means an individual, partnership, corporation, business trust, limited liability company, limited liability partnership, joint stock company, trust, unincorporated association, joint venture or other entity or a Governmental Authority. “PGA” (i.e., Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Physical Trade” has the meaning set forth in the CAISO Tariff. “Physical Trade Settlement Amount” means the dollar amount calculated in accordance with Exhibit L. “PIRP” (i.e., Participating Intermittent Resource Program) means the CAISO’s intermittent resource program initially established pursuant to Amendment No. 42 of the CAISO Tariff in Docket No. ER02-922-000, or any successor program that Buyer determines accomplishes a similar purpose. “PMax” has the meaning set forth in the CAISO Tariff. “PNode” has the meaning set forth in the CAISO Tariff. “Power Output” means the average rate of electric energy delivery during one Metering Interval, converted to an hourly rate of electric energy delivery, in kWh per hour, that is equal to the product of Metered Energy for one Metering Interval, in kWh per Metering Interval, times the number of Metering Intervals in a one-hour period. “Power Product” means (a) the Net Contract Capacity and (b) all electric energy produced by the Generating Facility, net of all Station Use and any and all of the Site Host Load. “PPT” means Pacific Daylight time when California observes Daylight Savings Time and Pacific Standard Time otherwise. “Primary Fuel” means the fuel or combination of fuels that are provided for in the Permits applicable to the Generating Facility. “Product” means the Power Product and the Related Products. “Project” means the Generating Facility. “Prudent Electrical Practices” means those practices, methods and acts that would be implemented and followed by prudent operators of electric generating facilities in the Western United States, similar to the Generating Facility, during the relevant time period, which

Exhibit A

Definitions

Page 21

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

practices, methods and acts, in the exercise of prudent and responsible professional judgment in the light of the facts known at the time a decision was made, could reasonably have been expected to accomplish the desired result consistent with good business practices, reliability and safety. Prudent Electrical Practices includes, at a minimum, those professionally responsible practices, methods and acts described in the preceding sentence that comply with the manufacturer’s warranties, restrictions in this Agreement, and the requirement of Governmental Authorities, WECC standards, the CAISO and Applicable Laws. Prudent Electrical Practices shall include taking reasonable steps to ensure that: (a) Equipment, materials, resources and supplies, including spare parts inventories, are available to meet the Generating Facility’s needs; (b) Sufficient operating personnel are available at all times and are adequately experienced, trained and licensed as necessary to Operate the Generating Facility properly and efficiently, and are capable of responding to reasonably foreseeable emergency conditions at the Generating Facility and Emergencies whether caused by events on or off the Site; (c) Preventative, routine, and non-routine maintenance and repairs are performed on a basis that ensures reliable, long term and safe operation of the Generating Facility, and are performed by knowledgeable, trained and experienced personnel utilizing proper equipment and tools; (d) Appropriate monitoring and testing are performed to ensure equipment is functioning as designed; (e) Equipment is not operated in a reckless manner, in violation of manufacturer’s guidelines or in a manner unsafe to workers, the general public or the Transmission Provider’s electric system, or contrary to environmental laws, permits or regulations or without regard to defined limitations, such as flood conditions, safety inspection requirements, operating voltage, current, volt ampere reactive (VAR) loading, frequency, rotational speed, polarity, synchronization, and control system limits; and (f) Equipment and components designed and manufactured to meet or exceed the standard of durability that is generally used for electric energy generation operations in the Western United States and will function properly over the full range of ambient temperature and weather conditions reasonably expected to occur at the Site and under both normal and emergency conditions. “PTSAi” has the meaning set forth in Section 2 of Exhibit L.

Exhibit A

Definitions

Page 22

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95-617, as amended from time to time. “QF PGA” (i.e., Qualifying Facility Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Qualifying Cogeneration Facility” means an electric energy generating facility that: (a)

Complies with the “qualifying cogeneration facility” definition and other requirements (including the requirements set forth in 18 CFR Part 292, Section 292.205) established by PURPA and any FERC rules as amended from time to time implementing PURPA, as set forth in 18 CFR Part 292, Section 292.203 et seq.; and

(b)

Has filed with the FERC (i) an application for FERC certification, pursuant to 18 CFR Part 292, Section 292.207(b)(1), which the FERC has granted, or (ii) a notice of selfcertification pursuant to 18 CFR Part 292, Section 292.207(a).

“RAR” means the resource adequacy requirements established for load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by a Local Regulatory Authority or other Governmental Authority having jurisdiction. “RAR Showings” means the RAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (or, to the extent authorized by the CPUC, to the CAISO), pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction. “Real-Time Forced Outage” means a Forced Outage which occurs only after 5:00 p.m. PPT on the day before the Trading Day. “Real-Time Market” has the meaning set forth in the CAISO Tariff. “Real-Time Price” means the Real-Time Market price for Uninstructed Imbalance Energy (as defined in the CAISO Tariff) or any successor price for short-term imbalance energy, as such price or successor price is defined in the CAISO Tariff, that would apply to the Generating Facility, which values are, as of the Effective Date, posted by the CAISO on its website. The values used in this Agreement will be those appearing on the CAISO website on the eighth Business Day of the calendar month following the month for which such prices are being applied. “Reference Market-Maker” means a leading dealer in the electric energy market that is not an Related Entity of either Party (or of a Trade Organization) and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker. Exhibit A

Definitions

Page 23

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Related Entity” means, with respect to a party, any Person that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with such party. For purposes of this Agreement, “control” means the direct or indirect ownership of 50% or more of the outstanding capital stock or other equity interests having ordinary voting power. “Related Products” means (i) with respect to Resource Adequacy Benefits (a) that portion of the Resource Adequacy Benefits that are associated with the Firm Contract Capacity, and (b) to the extent that there are Resource Adequacy Benefits associated with the generating capacity of the Generating Facility other than the Firm Contract Capacity, that portion of the Resource Adequacy Benefits that are not associated with the Firm Contract Capacity and that are in excess of those Resource Adequacy Benefits used by Seller or by a Site Host, both in connection with the Host Site, to meet a known and established resource adequacy obligation under any Resource Adequacy Ruling at the point in time when the Resource Adequacy Benefits are to be used, and (ii) any Green Attributes, Capacity Attributes and all other attributes associated with the electric energy or capacity of the Generating Facility (but not including any Financial Incentives) that are in excess of those Green Attributes, Capacity Attributes or other attributes used, or retained for future use, by Seller or a Site Host, both in connection with the Host Site, to meet a known and established, at the point in time when the relevant attribute(s) are to be used or retained, obligation under Applicable Law. “Renewable Energy Credit” has the meaning set forth in Public Utilities Code Section 399.12(g), as may be amended from time to time or as further defined or supplemented by Applicable Law. “Resource Adequacy Benefits” means the rights and privileges attached to the Generating Facility that satisfy any Person’s resource adequacy obligations, as those obligations are set forth in any Resource Adequacy Rulings and shall include any local, zonal or otherwise locational attributes associated with the Generating Facility. “Resource Adequacy Resource” has the meaning set forth in the CAISO Tariff. “Resource Adequacy Rulings” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 0606-024, 06-07-031 and any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable Governmental Authority, as such CPUC decisions, rulings, laws, rules or regulations may be amended or modified from time to time during the Term. “RPS Program” means the State of California Renewable Portfolio Standard Program, as codified at California Public Utilities Code Section 399.11, et seq. “Sale-Leaseback Transaction” means a transaction in which Seller (i) sells the Generating Facility to a Lender providing tax equity financing to Seller and (ii) leases the Generating Facility from Lender under an agreement authorizing Seller to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s

Exhibit A

Definitions

Page 24

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

right to terminate the lease in the event of a default by Seller as set forth in the agreement between Seller and Lender. “Schedule” means the action of the Scheduling Coordinator, or its designated representatives, of notifying, requesting, and confirming to the CAISO, the CAISO-Approved Quantity of electric energy. “Scheduled Amount” means the Day-Ahead Schedule comprised of the quantity (in MWh) of electric energy expected to be produced by the Generating Facility that is scheduled from Seller or Seller’s Scheduling Coordinator to Buyer in a Physical Trade in the IFM. “Scheduled Power Offline” is described in Section 3(b)(v) of Exhibit E. “Scheduling Coordinator” means a Person certified by the CAISO for the purposes of undertaking the functions specified in Exhibit G. “Scheduling Fee” means the Monthly Scheduling Fee and the SC Set-Up Fee. “SC Replacement Date” has the meaning set forth in Section 7(b) of Exhibit G. “SC Set-Up Fee” is described in Section 4(a) of Exhibit G. “SC Trade Settlement Amount” means the amount(s) determined in accordance with Exhibit M. “SC Trade Tolerance Band” means the greater of (a) three percent of the Scheduled Amount or (b) one MW. “SDD Administrative Charge” has the meaning set forth in Section 2 of Exhibit K. “SDD Adjustment” means the adjustment, if any, to the Monthly Contract Payment, as determined in accordance with Exhibit K. “SDD Energy Adjustment” has the meaning set forth in Section 1 of Exhibit K. “SEC” means the United States Securities and Exchange Commission, or any successor entity. “Self-Schedule” has the meaning set forth in the CAISO Tariff. “Seller” has the meaning set forth in the Preamble. “Seller’s Day-Ahead Forecast” means the most recently updated Forecast submitted by 5:00 p.m. PPT on the day before the Trading Day. “Seller’s Energy Forecast” means Seller’s most recently updated Forecast submitted in accordance with Exhibit I. Exhibit A

Definitions

Page 25

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Seller’s Final Energy Forecast” means Seller’s Energy Forecast as may be updated for Forced Outages that occur after the Hour-Ahead Scheduling Deadline, but not for Ambient Outages. “Settlement Agreement” has the meaning set forth in Recital C. “Settlement Effective Date” has the meaning set forth in Recital D. “Settlement Interval” has meaning set forth in the CAISO Tariff. “Settling Parties” has the meaning set forth in Recital B. “SGIA” (i.e., Small Generator Interconnection Agreement) means the form of Interconnection Request (as defined in the CAISO Tariff) pertaining to a Small Generating Facility (as defined in the CAISO Tariff), which is attached to the CAISO Tariff as Appendix T. “Simple Interest Payment” means a dollar amount calculated by multiplying the: (a) Dollar amount on which the Simple Interest Payment is based; by (b) Federal Funds Effective Rate or Interest Rate as applicable; by (c) The result of dividing the number of days in the calculation period by 360. “Site” means the real property on which the Generating Facility is located, as further described in Section 1.02(b) and Exhibit B. “Site Control” means that Seller (a) owns the Site, (b) is the lessee of the Site under a Lease, (c) is the holder of a right-of-way grant or similar instrument with respect to the Site, or (d) is managing partner or other Person authorized to act in all matters relating to the control and Operation of the Site and Generating Facility. “Site Host” means the Person or Persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating Facility. “Site Host Load” means the electric energy and capacity produced by or associated with the Generating Facility that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b). “SLIC” means Scheduling and Logging system for the CAISO. “Station Use” means the electric energy produced by the Generating Facility that is (a) used within the Generating Facility to power the lights, motors, control systems and other electrical loads that are necessary for Operation, and (b) consumed within the Generating Facility’s electric energy distribution system as losses needed to deliver electric energy to the Site Host Load, and

Exhibit A

Definitions

Page 26

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(c) consumed within the generator collection system as losses between the generator(s) and the high voltage side of the Generating Facility output transformer(s). “Successor” has the meaning set forth in Section 3.20(b)(iii). “Supply Plan” has the meaning set forth in the CAISO Tariff. “System Emergency” has the meaning set forth in the CAISO Tariff. “Tariff Rule 21” means the interconnection standards of the Transmission Provider for distributed generation adopted by the CPUC in Decisions 00-11-001 and 00-12-037, as modified by the CPUC. “Telemetry System” means a system of electronic components that interconnects the CAISO and the Generating Facility in accordance with the CAISO’s applicable requirements as set forth in Section 3.09. “Term” has the meaning set forth in Section 1.01. “Term End Date” has the meaning set forth in Section 1.01. “Termination Payment” has the meaning set forth in Section 6.03. “Term Start Date” has the meaning set forth in Section 1.01. “Term Year” means a 12-month period beginning on the first day of the Term and each successive 12-month period thereafter. “TOD Period” means the time of delivery period used to calculate the Monthly Contract Payment set forth in Section 4 of Exhibit D. “TOD Period Capacity Payment” means the monthly payment to be calculated and made by Buyer to Seller for Power Product capacity during each TOD Period for the month for which a calculation is being performed, as set forth in Section 3(a) of Exhibit D, in dollars. “TOD Period Energy Payment” means the monthly payment to be calculated and made by Buyer to Seller for the Metered Energy during each TOD Period for the month for which a calculation is being performed, as set forth in Section 2(a) of Exhibit D, in dollars. “TOD Period Energy Price” means the price used to calculate the TOD Period Energy Payment, as set forth in Exhibit S and referenced in Section 2(b) of Exhibit D, in dollars per kWh. “TOU” has the meaning set forth in Section 1 of Exhibit S.

Exhibit A

Definitions

Page 27

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“Trade Organizations” means the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, and the Independent Energy Producers Association. “Trading Day” means the day in which Day-Ahead trading occurs in accordance with the WECC Preschedule Calendar (as found on the WECC’s website). “Transmission Curtailment Credit Value” or “TCV” is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, as determined in accordance with Section 3 of Exhibit D-2. “Transmission Provider” means any Person responsible for the interconnection of the Generating Facility with the interconnecting utility’s electrical system or the CAISO Controlled Grid or transmitting the Metered Energy on behalf of Seller from the Generating Facility to the Delivery Point. “Transition EEI Agreement” means that certain Edison Electric Institute Master Power Purchase & Sale Agreement, together with the Cover Sheet, any amendments and annexes thereto (including the Collateral Annex and Paragraph 10 thereto) between Buyer and Seller, dated October 15, 2012. “Transition RA Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (RA Capacity), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement. “Transition Tolling Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (Energy Only UC Toll (Kern Pipeline – financially settled gas)), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement. “Uninstructed Deviation GMC Rate” means the administrative grid management charge applied by the CAISO to Uninstructed Deviations (as defined in the CAISO Tariff) using the absolute value for the Uninstructed Deviations by Settlement Interval. “Uninstructed Deviation Penalty” means the penalty set forth in the CAISO Tariff. “Useful Thermal Energy Output” has the meaning set forth in 18 CFR §292.202(h) and modified by the Energy Policy Act of 2005, or any successor thereto. “VOM” has the meaning set forth in Section 1 of Exhibit S. “Web Client” has the meaning set forth in Section 2(a) of Exhibit R. “Web Scheduler” has the meaning set forth in Section 2 of Exhibit E.

Exhibit A

Definitions

Page 28

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

“WECC” means the Western Electricity Coordinating Council, the regional reliability council for the western United States, northwestern Mexico, and southwestern Canada, or any successor entity. “WREGIS” means the Western Renewable Energy Generation Information System, or any successor thereto. *** End of Exhibit A ***

Exhibit A

Definitions

Page 29

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT B Generating Facility and Site Description 1.

Generating Facility Description. (a)

Generating Unit Features. Each Generating Unit has:

(b)

(i)

One General Electric Frame 7 gas turbine, with a nominal electric capacity rating of 76.56 MW;

(ii)

A bypass exhaust stack for simple cycle operation; and

(iii)

A heat recovery steam generator (HRSG) that is used to turn produced water from the oil field into steam for use in an enhanced oil recovery system.

Interconnection Utility System The Generating Facility has been operating in parallel with SCE’s Transmission System since 1985. The Generating Facility consists of a SCE designed and built 220kV switchyard with connections to the four generating units and to a SCE owned transmission line which transmits power to the SCE owned Magunden substation.

(d)

{Buyer Comment: Provide description of the Generating Facility equipment, systems, electric metering and the Seller’s measurement of theMeasurement of Useful Thermal Energy Output, control systems and features, including a site plan drawing and a oneline diagram, and the generator nameplate(s).}

Seller sells useful thermal energy output (steam) to Chevron U.S.A. Inc. for use in its enhanced oil recovery system under a long-term sales agreement. The Generating Facility supplies thermal energy in the form of saturated steam comprised of approximately 75% steam and 25% water. Useful thermal energy is calculated using the measured mass flow through the HRSG, measured feedwater temperature, measured steam pressure, measured steam quality, and the ASME steam tables to calculate BTU content of the steam. (e)

Control Systems The balance of plant control system is an Emerson Ovation Distributed Control System (DCS) utilizing redundant controllers. The redundant controllers provide

Exhibit B

Generating Facility and Site Description

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

greater reliability by allowing continued plant operation with the loss of a control processor. Multiple operator interfaces allow the plant operator to maintain control of the turbine with the loss of an operator interface. Non-critical equipment may be controlled by individual Programmable Logic Controller’s (PLC) or vendor supplied controllers that interface to the balance of plant DCS. (f)

Generating Unit #2 (i)

Name: Kern River Cogeneration Company Unit #2

(ii)

Location: Bakersfield, California

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 2

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: 77.25 MW.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South

(g)

(ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to maintain visibility and control of the turbine with the loss of an operator interface.

Generating Unit #4

Exhibit B

Generating Facility and Site Description

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(i)

Name: Kern River Cogeneration Company Unit #4

(ii)

Location: Bakersfield, California

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 4

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: 77.25 MW.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South

(h)

(ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to maintain visibility and control of the turbine with the loss of an operator interface.

Single-line Diagram

Exhibit B

Generating Facility and Site Description

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

  Exhibit B

Generating Facility and Site Description

Page 4

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(i)

Site Plan Drawing

Exhibit B

Generating Facility and Site Description

Page 5

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

 

Exhibit B

Generating Facility and Site Description

Page 6

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

2.

Site Description. {Buyer Comment: Provide a legal description of the Site, including the Site map.}

(a) Kern River Cogeneration Company Plant Site THAT PORTION OF SECTION 32, TOWNSHIP 28 SOUTH, RANGE 25 EAST, H.D.M., IN THE COUNTY OF KERN. STATE OF CALIFORNIA. DESCRIBED AS FOLLOWS: COMMENCING AT THE NORTHWEST CORNER OF SAID SECTION 32; THENCE SOUTH 00 DEGREES 22 MINUTES 14 SECONDS WEST ALONG THE WEST LINE OF THE NORTHWEST QUARTER OF SAID SECTION 32, A DISTANCE OF 1271.73 FEET; THENCE DEPARTING SAID WEST LINE SOUTH 85 DEGREES 37 MINUTES 46 SECONDS EAST A DISTANCE OF 2219.62 FEET TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION; THENCE (1) N.86 DEG. 36 MIN. 19 SEC E., A DISTANCE OF 88.81 FEET; THENCE (2) N.78 DEG. 25 MIN. 31 SEC E., A DISTANCE OF 36.40 FEET; THENCE (3) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 45.00 FEET; THENCE (4) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 40.00 FEET; THENCE (5) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 120.00 FEET; THENCE (6) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (7) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 13.00 FEET; THENCE (8) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (9) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 8.00 FEET; THENCE (10) N.10 DEG. 44 MIN. 52 SEC E., A DISTANCE OF 171.06 FEET; THENCE (11) N.18 DEG. 37 MIN. 55 SEC W., A DISTANCE OF 230.31 FEET; THENCE (12) N.13 DEG. 49 MIN. 58 SEC E., A DISTANCE OF 48.66 FEET; THENCE (13) N.41 DEG. 14 MIN. 26 SEC E., A DISTANCE OF 50.00 FEET; THENCE (14) N.56 DEG. 04 MIN. 49 SEC E., A DISTANCE OF 48.41 FEET; THENCE (15) N.77 DEG. 21 MIN. 00 SEC E., A DISTANCE OF 51.24 FEET; THENCE (16) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 43.00 FEET; THENCE (17) S.60 DEG. 42 MIN. 03 SEC E., A DISTANCE OF 156.59 FEET; THENCE (18) N.87 DEG. 20 MIN. 32 SEC E., A DISTANCE OF 73.55 FEET; THENCE (19) S.56 DEG. 34 MIN. 29 SEC E., A DISTANCE OF 30.89 FEET; THENCE (20) S.20 DEG. 32 MIN. 03 SEC E., A DISTANCE OF 30.87 FEET;

Exhibit B

Generating Facility and Site Description

Page 7

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

THENCE (21) S.06 DEG. 54 MIN. 55 SEC W., A DISTANCE OF 225.22 FEET; THENCE (22) S.04 DEG. 22 MIN. 14 SEC W., A DISTANCE OF 90.00 FEET; THENCE (23) S.03 DEG. 11 MIN. 03 SEC W., A DISTANCE OF 95.34 FEET; THENCE (24) S.01 DEG. 19 MIN. 04 SEC W., A DISTANCE OF 75.11 FEET; THENCE (25) S.17 DEG. 07 MIN. 51 SEC E., A DISTANCE OF 35.47 FEET; THENCE (26) S.19 DEG. 37 MIN. 32 SEC W., A DISTANCE OF 34.21 FEET; THENCE (27) S.12 DEG. 52 MIN. 15 SEC E., A DISTANCE OF 30.36 FEET; THENCE (28) S.82 DEG. 43 MIN. 07 SEC E., A DISTANCE OF 59.08 FEET; THENCE (29) S.66 DEG. 18 MIN. 47 SEC E., A DISTANCE OF 102.79 FEET; THENCE (30) N.89 DEG. 14 MIN. 33 SEC E., A DISTANCE OF 78.31 FEET; THENCE (31) N.53 DEG. 27 MIN. 22 SEC E., A DISTANCE OF 19.85 FEET; THENCE (32) N.18 DEG. 54 MIN. 18 SEC E., A DISTANCE OF 27.89 FEET; THENCE (33) N.76 DEG. 33 MIN. 06 SEC E., A DISTANCE OF 29.41 FEET; THENCE (34) N.60 DEG. 40 MIN. 50 SEC E., A DISTANCE OF 14.42 FEET; THENCE (35) N.24 DEG. 01 MIN. 28 SEC E., A DISTANCE OF 29.73 FEET; THENCE (36) S.74 DEG. 54 MIN. 59 SEC E., A DISTANCE OF 37.66 FEET; THENCE (37) N.80 DEG. 20 MIN. 04 SEC E., A DISTANCE OF 49.48 FEET; THENCE (38) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 20.00 FEET; THENCE (39) S.55 DEG. 03 MIN. 01 SEC E., A DISTANCE OF 25.55 FEET; THENCE (40) S.30 DEG. 37 MIN. 17 SEC E., A DISTANCE OF 24.41 FEET; THENCE (41) S.03 DEG. 13 MIN. 27 SEC E., A DISTANCE OF 30.27 FEET; THENCE (42) S.16 DEG. 11 MIN. 08 SEC E., A DISTANCE OF 42.27 FEET; THENCE (43) S.37 DEG. 28 MIN. 55 SEC W., A DISTANCE OF 109.84 FEET; THENCE (44) S.00 DEG. 13 MIN. 33 SEC W., A DISTANCE OF 207.54 FEET; THENCE (45) S.61 DEG. 20 MIN. 48 SEC W., A DISTANCE OF 23.85 FEET; THENCE (46) N.79 DEG. 55 MIN. 08 SEC W., A DISTANCE OF 20.10 FEET; THENCE (47) N.50 DEG. 43 MIN. 37 SEC W., A DISTANCE OF 52.43 FEET; THENCE (48) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 80.00 FEET; THENCE (49) S.47 DEG. 58 MIN. 24 SEC W., A DISTANCE OF 58.00 FEET; THENCE (50) S.00 DEG. 38 MIN. 21 SEC W., A DISTANCE OF 46.10 FEET; THENCE (51) S.25 DEG. 29 MIN. 43 SEC W., A DISTANCE OF 47.17 FEET; THENCE (52) S.74 DEG. 02 MIN. 51 SEC W., A DISTANCE OF 57.58 FEET; THENCE (53) S.71 DEG. 32 MIN. 13 SEC W., A DISTANCE OF 20.62 FEET; THENCE (54) N.84 DEG. 29 MIN. 01 SEC W., A DISTANCE OF 50.01 FEET; THENCE (55) S.87 DEG. 51 MIN. 03 SEC W., A DISTANCE OF 70.46 FEET;

Exhibit B

Generating Facility and Site Description

Page 8

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

THENCE (56) S.78 DEG. 15 MIN. 26 SEC W., A DISTANCE OF 46.84 FEET; THENCE (57) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 40.36 FEET; THENCE (58) S.74 DEG. 57 MIN. 33 SEC W., A DISTANCE OF 111.33 FEET; THENCE (59) N.63 DEG. 11 MIN. 37 SEC W., A DISTANCE OF 167.69 FEET; THENCE (60) N.45 DEG. 49 MIN. 26 SEC W., A DISTANCE OF 39.05 FEET; THENCE (61) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 26.91 FEET; THENCE (62) N.04 DEG. 59 MIN. 23 SEC W., A DISTANCE OF 92.23 FEET; THENCE (63) N.07 DEG. 43 MIN. 27 SEC W., A DISTANCE OF 71.59 FEET; THENCE (64) N.19 DEG. 15 MIN. 01 SEC E., A DISTANCE OF 214.18 FEET; THENCE (65) N.07 DEG. 53 MIN. 39 SEC W., A DISTANCE OF 23.54 FEET; THENCE (66) N.35 DEG. 26 MIN. 06 SEC W., A DISTANCE OF 31.24 FEET; THENCE (67) N.63 DEG. 49 MIN. 41 SEC W., A DISTANCE OF 16.16 FEET; THENCE (68) N.81 DEG. 48 MIN. 55 SEC W., A DISTANCE OF 75.17 FEET; THENCE (69) S.86 DEG. 24 MIN. 03 SEC W., A DISTANCE OF 50.49 FEET; THENCE (70) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 34.00 FEET; TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION. (b)

Site Control Seller has legal control of the Site under a 1984 Ground Lease from Chevron U.S.A. (CUSA), as amended in 1985 and 2005. Seller also has easement agreements with CUSA providing for ingress and egress to the Site and all other necessary rights-ofway for operation of Seller.

(c)

Site Map

Exhibit B

Generating Facility and Site Description

Page 9

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Exhibit B

Generating Facility and Site Description

Page 10

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

*** End of Exhibit B ***

Exhibit B

Generating Facility and Site Description

Page 11

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT C [Intentionally omitted.] *** End of Exhibit C ***

Exhibit C

[Intentionally omitted.]

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT D Monthly Contract Payment Calculation

1.

Introduction. Each Monthly Contract Payment is calculated on a calendar month basis as follows: MONTHLY CONTRACT PAYMENT, in dollars = TOD Period Energy Payment 1st TOD Period TOD Period Energy Payment 2nd TOD Period TOD Period Energy Payment 3rd TOD Period TOD Period Energy Payment 4th TOD Period TOD Period Capacity Payment 1st TOD Period TOD Period Capacity Payment 2nd TOD Period TOD Period Capacity Payment 3rd TOD Period TOD Period Capacity Payment 4th TOD Period

+ + + + + + +

All TOD Period Energy Payments shall be calculated as set forth in Section 2 of this Exhibit D. All TOD Period Capacity Payments shall be calculated as set forth in Section 3 of this Exhibit D. The “1st TOD Period,” “2nd TOD Period,” “3rd TOD Period” and “4th TOD Period” subscripts refer to the four TOD Periods that apply for the calculation month, as set forth in Section 4 of this Exhibit D. 2.

TOD Period Energy Payment Calculation. (a)

Each monthly TOD Period Energy Payment is calculated as follows: LastHour

TOD PERIOD ENERGY PAYMENT, in dollars = LA x MA]



FirstHour

[(EP-LA) x APE +

Where: EP

= TOD Period Energy Price, stated in Section 2(b) of this Exhibit D, in dollars per kWh.

Exhibit D

Monthly Contract Payment Calculation

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D. LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D. LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. MA = Metered Amounts for each hour of the applicable TOD Period, in kWh. Metered Amounts for any hour is equal to the sum of Metered Amounts for all Metering Intervals in that hour. First Hour = First hour of the applicable TOD Period. Last Hour = Last hour of the applicable TOD Period. Once 120% of the Expected Term Year Net Energy Production is achieved, no further electric energy payments will be calculated for the remaining TOD Periods within any remaining months of the current Term Year. (b)

Factor “EP” in Section 2(a) of this Exhibit D. The TOD Period Energy Price, in dollars per kWh, for any TOD Period shall be calculated pursuant to and as determined by the methodology set forth in Exhibit S.

(c)

Factor “APE” in Section 2(a) of this Exhibit D. The Allowed Payment Energy for each hour of each TOD Period of any month is calculated as follows: APE = The sum of the Metered Energy when Buyer is Scheduling Coordinator or Scheduled Amounts when Buyer is not Scheduling Coordinator from the Generating Facility for each hour of the TOD Period, in kWh.

3.

TOD Period Capacity Payment Calculation. (a)

Each monthly TOD Period Capacity Payment is calculated on a calendar month basis as follows: TOD PERIOD CAPACITY PAYMENT in dollars = (ACP + FCP) x CAF Where: ACP =

As-Available Capacity Payment for the TOD Period, as determined in accordance with Section 3(b) of this Exhibit D, in dollars per year.

Exhibit D

Monthly Contract Payment Calculation

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

FCP =

Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(g) of this Exhibit D, in dollars per year.

CAF =

The CPUC approved Capacity Payment Allocation Factor for the TOD Period in the year, based upon the formula adopted by the CPUC in D.01-03-067 [and D.97-03-017. For purposes of this Agreement, the CPUC approved Capacity Payment Allocation Factors are as provided in the table below, allocated to each month of the season based on the proportion of the month’s hours in the TOD Period to the season’s hours in TOD Period, and may be updated per subsequent CPUC decision]: Season Summer

Winter

Capacity Payment Allocation Factors TOD Period Peak Partial Peak Off Peak Super Off Peak Peak Partial Peak Off Peak Super Off Peak

Factor 0.7619 .0238 .0002 0.00000 N/A 0.2125 0.0015 0.00000

{Buyer Comment: Use the Capacity Payment Allocation Factors set forth in the table immediately above if Buyer is PG&E. Additionally, the bracketed text is only applicable if Buyer is PG&E, and should otherwise be deleted.} Season Summer Winter

Capacity Payment Allocation Factors TOD Period On-Peak Period Mid-Peak Off-Peak Mid-Peak Off-Peak Super-Off-Peak

Factor 0.1792 0.0310 0.0006 0.0178 0.0011 0.0007

{Buyer Comment: Use the Capacity Payment Allocation Factors set forth in the table immediately above if Buyer is SCE.}

Exhibit D

Monthly Contract Payment Calculation

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company Capacity Payment Allocation Factors Season

TOD Period On-Peak Semi-Peak Off-Peak Super Off-Peak Non TOU On-Peak Semi-Peak Off-Peak Super Off-Peak Non TOU

Summer

Winter

Factor 0.098096 0.006146 0.000000 0.000000 0.002088 0.013237 0.008118 0.000000 0.000000 0.002008

{Buyer Comment: Use the Capacity Payment Allocation Factors set forth set forth in the table immediately above if Buyer is SDG&E.}

(b)

Factor “ACP” in Section 3(a) of this Exhibit D. The As-Available Capacity Payment shall be calculated pursuant to the following formula: AS-AVAILABLE CAPACITY PAYMENT, in dollars = AAC x AACP Where: AAC = As-Available Capacity for the TOD Period, as determined in accordance with Section 3(c) of this Exhibit D, in kWh per hour. AACP= The As-Available Capacity Price adopted by the CPUC in the Decision for the applicable year as set forth in the following table: Year 2011 2012 2013 2014 2015

(c)

As-Available Capacity Price Price $/kW-yr 41.22 43.09 45.00 46.97 48.98

Factor “AAC” in Section 3(b) of this Exhibit D. The As-Available Capacity for each TOD Period of each month is calculated as follows: AS-AVAILABLE CAPACITY, in kWh per hour = MAC – FCC (but not less than zero) Where:

Exhibit D

Monthly Contract Payment Calculation

Page 4

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

MAC = The Maximum Allowed Capacity for the TOD Period as determined in Section 3(d) in this Exhibit D, in kWh per hour. FCC = The Firm Contract Capacity for all TOD Periods during a month. (d)

Factor “MAC” in Section 3(c) of this Exhibit D. The Maximum Allowed Capacity for each monthly TOD Period is calculated as follows: MAXIMUM ALLOWED CAPACITY, in kWh per hour

= LE / PH

Where: LE

= The sum of the Limited TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(e) of this Exhibit D, in kWh.

PH = The total number of hours in the TOD Period (period hours). (e)

Factor “LE” in Section 3(d) of this Exhibit D. The Limited TOD Energy for each TOD Period of any month is calculated as follows: LastHour

LIMITED TOD ENERGY, in kWh =



FirstHour

(E)Hour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour, in kWh; and (ii) Allowed Hourly Energy, as determined in Section 3(f) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (f)

Factor “E” in Section 3(e) of this Exhibit D. The Allowed Hourly Energy is calculated as follows: ALLOWED HOURLY ENERGY in kWh

= 1 hour x NCC

Where: NCC = The Net Contract Capacity, as set forth in Section 1.02(d), in kW.

Exhibit D

Monthly Contract Payment Calculation

Page 5

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(g)

Factor “FCP” in Section 3(a) of this Exhibit D. Each monthly Firm Capacity Payment is calculated as follows: FIRM CAPACITY PAYMENT in dollars = MFCP x AF Where: MFCP = Maximum Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(h) of this Exhibit D, in dollars. AF

= (i)

One (1), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is greater than or equal to 95%; or

(ii)

Zero (0), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is less than 60%; or

(iii) If neither (i) nor (ii) are true, then AF is the Availability Penalty Factor, as calculated in Section 3(n) of this Exhibit D. (h)

Factor “MFCP” in Section 3(g) of this Exhibit D. The Maximum Firm Capacity Payment for each TOD Period of each month is calculated as follows: MAXIMUM FIRM CAPACITY PAYMENT, in dollars = FCC x CP Where: FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d), in kWh per hour. CP

(i)

= Firm Capacity Price, as set forth in Section 1.06(a), in $/kW-year.

Factor “ACF” in Section 3(g) of this Exhibit D. The Availability Credit Factor for each monthly TOD Period is calculated as follows: AVAILABILITY CREDIT FACTOR

= (ECH + CCH) / PH

Where: ECH = The total number of Earned Capacity Hours, determined in accordance with Section 3(j) of this Exhibit D. CCH = The total number of Capacity Credit Hours, determined in accordance with Section 3(m) of this Exhibit D. PH = The total number of hours in the TOD Period (period hours).

Exhibit D

Monthly Contract Payment Calculation

Page 6

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(j)

Factor “ECH” in Section 3(i) of this Exhibit D. The Earned Capacity Hours for each monthly TOD Period is calculated as follows: EARNED CAPACITY HOURS

=

FE / FCC

Where: FE

= The sum of the Firm TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(k) of this Exhibit D, in kWh.

FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d) in kWh per hour. (k)

Factor “FE” in Section 3(j) of this Exhibit D. The Firm TOD Energy for each TOD Period of any month is calculated as follows: LastHour

FIRM TOD ENERGY in kWh

=



FirstHour

(E)Hour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour in kWh; and (ii) Allowed Firm Energy, as determined in Section 3(l) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (l)

Factor “E” in Section 3(k) of this Exhibit D. The Allowed Firm Energy is calculated as follows: ALLOWED FIRM ENERGY in kWh

= 1 hour x FCC

Where: FCC = The Firm Contract Capacity set forth in Section 1.02(d). (m)

Factor “CCH” in Section 3(i) of this Exhibit D. The total number of Capacity Credit Hours for each monthly TOD Period is determined as follows:

Exhibit D

Monthly Contract Payment Calculation

Page 7

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

CAPACITY CREDIT HOURS

= TCV + FCV + MCV

Where: TCV = The total Transmission Curtailment Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-2, when the Metered Energy was curtailed by either the CAISO or the Transmission Provider. FCV = The total Force Majeure Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-1, when the Metered Energy was curtailed by a Force Majeure event claimed by Buyer to the extent the Generating Facility is otherwise available. MCV = The total Maintenance Credit Value during the TOD Period, determined in accordance with Section 9 of Exhibit E. (n)

Factor “APF” in Section 3(g) of this Exhibit D. The Availability Penalty Factor for each monthly TOD Period is calculated as follows: AVAILABILITY PENALTY FACTOR = 1.0 – 2.0 x (CR – ACF) Where: APF = The greater of: (i) zero; and (ii) the result of the above equation for APF. CR = 95%, the minimum Capacity Performance Requirement. ACF = The Availability Credit Factor determined in accordance with Section 3(i) of this Exhibit D.

4.

Time of Delivery Periods. SEASON AND TIME PERIOD Period A - Summer

Period B - Winter

May 1 - October 31

November 1 - April 30

Applicable Days

Peak

Noon - 6:00 p.m.

NA

Weekdays except Holidays

Partial-Peak

8:30 a.m. - Noon

8:30 a.m. - 9:30 p.m.

Weekdays except Holidays

Time Period

6:00 p.m. - 9:30 p.m. Off-Peak

Super Off-Peak

Weekdays except Holidays

9:30 p.m. - 1:00 a.m.

9:30 p.m. - 1:00 a.m.

Weekdays except Holidays

5:00 a.m. - 8:30 a.m.

5:00 a.m. - 8:30 a.m.

Weekdays except Holidays

5:00 a.m. - 1:00 a.m.

5:00 a.m. - 1:00 a.m.

Weekends & Holidays

1:00 a.m. - 5:00 a.m.

1:00 a.m. - 5:00 a.m.

All Days

Exhibit D

Monthly Contract Payment Calculation

Page 8

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

{Buyer Comment: Use the Time of Delivery Periods set forth set forth in the table immediately above if Buyer is PG&E.} TOD Period On-Peak

Summer Jun 1st – Sep 30th Noon – 6:00 p.m.

Winter Oct 1st – May 31st Not Applicable.

8:00 a.m. – Noon

Applicable Days Weekdays except Holidays. Weekdays except Holidays.

Mid-Peak

8:00 a.m. - 9:00 p.m. 6:00 p.m. – 11:00 p.m.

Weekdays except Holidays. 6:00 a.m. – 8:00 a.m.

Weekdays except Holidays.

9:00 p.m. – Midnight

Weekdays except Holidays.

Midnight – Midnight

6:00 a.m. – Midnight

Weekends and Holidays.

Not Applicable.

Midnight – 6:00 a.m.

Weekdays, Weekends and Holidays.

11:00 p.m. – 8:00 a.m. Off-Peak

Super-Off-Peak

{Buyer Comment: Use the Time of Delivery Periods set forth set forth in the table immediately above if Buyer is SCE.}

Time Period ON-PEAK SEMI-PEAK OFF-PEAK

Super Off-Peak

Summer

Winter

MAY 1 - SEPTEMBER 30

OCTOBER 1 - APRIL 30

11:00 a.m. - 6:00 p.m.

5:00 p.m. - 8:00 p.m.

Weekdays

6:00 a.m. - 11:00 a.m.

6:00 a.m. - 5:00 p.m.

Weekdays

6:00 p.m. - 10:00 p.m.

8:00 p.m. - 10:00 p.m.

Weekdays

10:00p.m. - 12:00 mid.

10:00 p.m. - 12:00 mid.

Weekdays

5:00 a.m. - 6:00 a.m.

5:00 a.m. - 6:00 a.m.

Weekdays

5:00 a.m. - 12:00 mid.

5:00 a.m. - 12:00 mid.

Weekends

5:00 a.m. - 12:00 mid.

5:00 a.m. - 12:00 mid.

Holidays

12:00 mid. - 5:00 a.m.

12:00 mid. - 5:00 a.m.

All Days

{Buyer Comment: Use the Time of Delivery Periods set forth set forth in the table immediately above if Buyer is SDG&E.}

“Holiday”, as used in the above table, means New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. When a Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. *** End of Exhibit D ***

Exhibit D

Monthly Contract Payment Calculation

Page 9

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT D-1 Force Majeure Credit Value 1.

Overview. This Exhibit D-1 describes the methodology for computing Force Majeure Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Force Majeure Credit Value. For every period of Force Majeure curtailment requested by Buyer, Buyer shall compute the Force Majeure Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-1, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the Force Majeure event and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of Benchmark Capacity minus Hourly Power Output or zero

Exhibit D-1

Force Majeure Credit Value

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

In case of division by zero, the value being calculated shall be zero. (c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Force Majeure Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Force Majeure Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. *** End of Exhibit D-1 ***

Exhibit D-1

Force Majeure Credit Value

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT D-2 Transmission Curtailment Credit Value 1.

Overview. This Exhibit D-2 describes the methodology for computing Transmission Curtailment Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Transmission Curtailment Credit Value. For every period of curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, Buyer shall compute the Transmission Curtailment Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-2, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the curtailment notification and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of: Benchmark Capacity minus Hourly Power Output or zero In case of division by zero, the value being calculated shall be zero.

Exhibit D-2

Transmission Curtailment Credit Value

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Transmission Curtailment Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Transmission Curtailment Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. ______________________________________________________________________________ *** End of Exhibit D-2 ***

Exhibit D-2

Transmission Curtailment Credit Value

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT E Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits 1.

Overview. Seller shall follow the protocols established in this Exhibit E for the scheduling of Maintenance Outages and Major Overhauls, and for any subsequent notification that may be required to update a previously scheduled Maintenance Outage or Major Overhaul for which Seller wishes to obtain Maintenance Credit Value. This Exhibit E also describes the methodology for computing Maintenance Credit Value and Maintenance Debit Value.

2.

Notification. Seller shall direct all Maintenance Outage and Major Overhaul notifications to Buyer’s web-based outage scheduling system or an e-mail address designated by Buyer (the “Web Scheduler”) and to the Generation Operations Center, whose URL and telephone number(s) can be found in Exhibit N.

3.

Scheduling. (a)

Seller shall schedule all Maintenance Outages and Major Overhauls with Buyer in advance. Seller’s failure to schedule an unplanned outage in advance is not a default under this Agreement. The notice requirements for Maintenance Outages and Major Overhauls are as follows: Outage Duration Maintenance Outage, Less than 1 day Maintenance Outage, 1 day or more Major Overhaul

(b)

Exhibit E

Minimum Advance Notice 24 Hours 168 Hours 6 Months

Seller shall provide the following information when scheduling a Maintenance Outage or a Major Overhaul via the Web Scheduler: (i)

The identification number set forth on the cover page of this Agreement;

(ii)

Password (supplied by Buyer);

(iii)

Generating Unit Number*;

(iv)

Capacity Credit Period, including: (1)

The date and time when Seller expects the Capacity Credit Period to begin, and

(2)

The date and time when Seller expects the Capacity Credit Period to end.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(v)

“Scheduled Power Offline”**, in kW, is the Hourly Power Output that is expected to be offline during each hour of the outage period, as such may be updated as set forth in this Exhibit E; and

(vi)

Reason for the requested Maintenance Outage or Major Overhaul.

*Unit designation is applicable only when the contract calls for separate tracking of outage allowance for each Generating Unit. **If unit designation is applicable, Seller must provide the expected Scheduled Power Offline of the Generating Unit scheduled for maintenance; otherwise, Seller must provide the expected Scheduled Power Offline of the Generating Facility. 4.

Rescheduling. (a)

A Maintenance Outage and the associated Capacity Credit Period may be rescheduled if Seller’s request to reschedule is received by Buyer no later than 5:00 p.m. PPT on the day before the Maintenance Outage was previously scheduled to begin.

(b)

A Major Overhaul and the associated Capacity Credit Period may be rescheduled provided:

(c) 5.

(i)

The rescheduled Major Overhaul begins six months or more after the first outage notification date and time;

(ii)

The notification to reschedule is made at least one week before the Major Overhaul was previously scheduled to begin; and

(iii)

There is at least a one-month period between the notification to reschedule and the commencement of the rescheduled Major Overhaul.

Maintenance Outages and Major Overhauls may be rescheduled more than once.

Extension. (a)

Exhibit E

Seller may extend a Maintenance Outage or a Major Overhaul and the associated Capacity Credit Period by notifying Buyer of the extension no later than 5:00 p.m. PPT on the day before the outage was previously scheduled to end. Seller’s failure to provide such notice, to the extent resulting from unexpected circumstances, is not a default under this Agreement.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(b)

Maintenance Outages and Major Overhauls and the associated Capacity Credit Periods may be extended more than once.

(c)

For a Maintenance Outage and the associated Capacity Credit Period which is less than 24 hours in duration, the extension cannot result in a total outage duration greater than 23 hours.

6.

Cancellation. If Seller cancels a scheduled Maintenance Outage, Major Overhaul or the associated Capacity Credit Period, a cancellation notice must be received by Buyer no later than 5:00 p.m. PPT on the day before such Maintenance Outage or Major Overhaul was scheduled to begin.

7.

Updating Scheduled Power Offline.

8.

(a)

If a change in the Hourly Power Output is anticipated or occurs during a Maintenance Outage or a Major Overhaul, the Scheduled Power Offline must be updated on a prospective basis as soon as possible via the Web Scheduler. Scheduled Power Offline cannot be updated once the Maintenance Outage or Major Overhaul is over.

(b)

Multiple updates to the Scheduled Power Offline can be submitted if necessary on a prospective basis.

(c)

If a Maintenance Outage or a Major Overhaul is completed ahead of schedule and Seller’s Hourly Power Output has returned to normal output levels earlier than expected, Seller shall advise Buyer of the situation by providing an update to the Scheduled Power Offline as described in Section 7(a) of this Exhibit E.

Restrictions. (a)

Seller shall make reasonable efforts not to schedule a Maintenance Outage or Major Overhaul during the Peak Months. Should an outage be required during the said period, Seller shall abide by the limit as set forth in Section 1.05(d) for minor maintenance work during peak months.

(b)

Each Capacity Credit Period must be scheduled to start and stop at the beginning of an hour. Also, when scheduling an outage, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

(c)

Seller may not schedule a Maintenance Outage or a Major Overhaul that overlaps another Maintenance Outage, Major Overhaul, or Curtailment Period already scheduled on the Generating Facility. If unit designation is applicable in Section 3(b)(iii) of this Exhibit E, this restriction applies to the Generating Unit.

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

9.

Maintenance Credit Calculation. For every properly scheduled Maintenance Outage and Major Overhaul, to the extent there is an associated Capacity Credit Period, Buyer shall compute and apply the associated Maintenance Credit Value and the Maintenance Debit Value following these steps: (a)

A Benchmark Capacity shall be determined for every scheduled Maintenance Outage and Major Overhaul. For purposes of this Exhibit E, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, at or after the time of outage notification, and before the start of the outage. If the outage is rescheduled, the most recent notification time shall be used in defining Benchmark Capacity. If the outage is extended, or its Scheduled Power Offline is updated, the original notification time shall be used in defining Benchmark Capacity, unless the outage has been rescheduled before the extension, in which case the most recent rescheduling notification time shall be used in defining Benchmark Capacity. In the special case of a less-than-one-day Maintenance Outage that directly follows another less-than-one-day Maintenance Outage, Benchmark Capacity of the outage that follows is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, between these two outage time periods. In the event of back-to-back, less-than-one-day Maintenance Outages, Benchmark Capacity for the second outage shall be zero. Notwithstanding this Section 9(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Capacity Credit Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during such Capacity Credit Period.

(b)

For each hour in the Capacity Credit Period of the Maintenance Outage or the Major Overhaul, an Hourly Credit Value and Hourly Debit Value shall be calculated using following formulas: (i)

Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the lesser of Benchmark Capacity minus Hourly Power Output, or Scheduled Power Offline.

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 4

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

However, in all cases, Delta shall never be less than zero. (ii)

Hourly Debit Value = (Scheduled Power Offline / Firm Contract Capacity) * 1 hour

(c)

For each hour in the Capacity Credit Period, the Hourly Credit Value shall be applied as Maintenance Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Capacity Credit Period have been applied, or until the condition described in Section 9(d) of this Exhibit E is met, whichever comes first.

(d)

Simultaneous to Section 9(c) of this Exhibit E, for each hour in the Capacity Credit Period, the Hourly Debit Value shall be accumulated as Maintenance Debit Value in a Term-Year-to-date account whose increasing total is to be compared to the appropriate limit set forth in Sections 1.05(a) or (b). Once the Term-Year-todate total reaches or exceeds the limit, no more Hourly Credit Values shall be applied.

(e)

After all the Hourly Credit Values have been applied and the Hourly Debit Values accounted for, the final monthly Maintenance Credit Value and the Term-Year-todate cumulative Maintenance Debit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision.

The above description of the evaluation process assumes that the outage was properly scheduled with sufficient advance notice pursuant to this Exhibit E and was approved by Buyer (or the CAISO, if applicable). Any deviation from the proper scheduling protocol can result in reduced Maintenance Credit Value or increased Maintenance Debit Value. *** End of Exhibit E ***

Exhibit E

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

Page 5

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT F [Intentionally omitted.] *** End of Exhibit F ***

Exhibit F

[Intentionally omitted.] Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT G Scheduling Coordinator Services This Exhibit G is only applicable when Buyer is Scheduling Coordinator. 1.

2.

Designation of Buyer as Scheduling Coordinator. (a)

At least 30 days before the Term Start Date, Seller shall take all actions and execute and deliver to Buyer and the CAISO all documents necessary to authorize or designate Buyer as Scheduling Coordinator with the CAISO effective as of the Term Start Date.

(b)

During the Term, unless Seller terminates Buyer as Scheduling Coordinator in accordance with Section 7 of this Exhibit G, Seller may not authorize or designate any other party to act as Scheduling Coordinator, nor shall Seller perform for its own benefit the duties of Scheduling Coordinator, and Seller may not revoke Buyer’s authorization to act as Scheduling Coordinator unless agreed to by Buyer.

(c)

Buyer shall submit bids and schedules to the CAISO in accordance with the CAISO Tariff and Seller’s QF PGA or PGA, as applicable.

(d)

Buyer shall submit all required notices and updates regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO in accordance with the CAISO procedures.

(e)

Seller is not entitled to any Monthly Capacity Payment until Buyer is fully authorized as Scheduling Coordinator for the Generating Facility; provided, however, that Buyer may not take, or not refrain from taking, any action if the result would be to delay such authorization.

Buyer’s Scheduling Responsibilities. Pursuant to the CAISO Tariff, Buyer shall be responsible for the following: (a)

Using the Forecast submitted by Seller to Buyer pursuant to Exhibit I, including updated Forecasts to the extent reasonably practicable, to forecast Seller’s expected generation using Buyer’s forecasting model (“Buyer Projected Energy Forecast”) in any given hour;

(b)

Adjusting Buyer Projected Energy Forecast for forecasted electric energy line losses in accordance with the amount of electric energy Seller is expected to deliver to the Delivery Point;

(c)

Submitting the adjusted Forecasts to the CAISO as Scheduling Coordinator Schedules (as defined in the CAISO Tariff); and

Exhibit G

Scheduling Coordinator Services

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(d)

Receiving notification of the final schedules from the CAISO.

3.

Notices. As Scheduling Coordinator, Buyer shall submit all notices and updates required under the CAISO Tariff and Applicable Laws regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO, including all SLIC Outage requests, SLIC Forced Outages, CAISO Forced Outage Reports, or must offer waiver forms.

4.

Scheduling Fees. In accordance with Section 4.02, Buyer shall invoice to Seller and Seller shall pay to Buyer the following Scheduling Fees: (a)

SC Set-Up Fee. The SC Set-Up Fee is equal to the costs Buyer incurs as a result of the Generating Units or the Generating Facility registration, as applicable, as well as installation, configuration, and testing of all equipment and software necessary, in Buyer’s sole discretion, to Schedule the Generating Unit or the Generating Facility, as applicable, in accordance with the CAISO Tariff. Buyer’s invoice to Seller shall provide a detailed accounting of all costs and charges encompassed in the SC Set-Up Fee, including separate line items for registration charges, equipment costs, software costs, and labor costs (including hourly rate if applicable) itemized for registration, equipment installation, configuration, testing and software related charges. Buyer estimates that the SC Set-up Fee for this Agreement will equal $[___].1,450.

(b)

Monthly Scheduling Fee. The Monthly Scheduling Fee will be as forth in the following table.

Net Contract Capacity (kW)

Monthly Scheduling Fee

Less than 10,000

$2,500

10,000 – 100,000

$5,000

Greater than 100,000

$7,500

5. CAISO Settlements. As Scheduling Coordinator, Buyer shall be responsible for all settlement functions with the CAISO related to the Generating Units or the Generating Facility, as applicable. Seller shall cooperate with Buyer in Buyer’s performance of any settlement functions, and Seller shall promptly deliver to Buyer, or provide Buyer access to, all Generating Unit or the Generating Facility, as applicable, data necessary for CAISO settlements and any correspondence or communications with CAISO related to the Generating Units or the Generating Facility, as applicable, including any invoices or settlement data, in the mutually agreed upon format reasonably requested by Buyer.

Exhibit G

Scheduling Coordinator Services

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Buyer shall render a separate invoice to Seller for all CAISO Charges for which Seller is responsible under this Agreement (“CAISO Charges Invoice”) as described in Sections 1 through 4 of Exhibit J, in accordance with the applicable billing and payment methodologies utilized for the specific CAISO Charge as set forth in the CAISO Tariff. CAISO Charges Invoices shall be rendered after final settlement information becomes available from the CAISO that identifies any CAISO Charges. At Seller’s request, Buyer shall provide Seller with an invoice detailing all Generating Facility CAISO Charges by individual CAISO Charge codes or types used by CAISO to identify individual CAISO Charges including a copy of all supplemental or supporting documentation provided by the CAISO to Buyer in the settlement process. Seller shall pay the amount of CAISO Charges Invoices on or before the later of the 20th day of each month, or tenth day after receipt of the CAISO Charges Invoice or, if such day is not a Business Day, then on the next Business Day. If Seller fails to pay a CAISO Charges Invoice within such timeframe, Buyer may offset any amounts owing to it for these CAISO Charges Invoices as set forth in Section 4.02. 6.

Disputes and Adjustments of CAISO Invoices. The Parties agree that all CAISO Charges Invoices are subject to the CAISO Tariff and may be adjusted by the CAISO, or disputed by Buyer, as Scheduling Coordinator, in accordance with the CAISO Tariff. The Parties agree that all CAISO Charges Invoices are subject to dispute between the Parties in accordance with this Agreement. Notwithstanding anything to the contrary contained in this Agreement, the Parties agree that the obligations under this Exhibit G with respect to the payment of CAISO Charges Invoices, or the adjustment of such CAISO Charges Invoices, shall survive the expiration or termination of this Agreement for a period of 365 days beyond the time period which CAISO may adjust, modify or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the CAISO Tariff.

7.

Terminating Buyer’s Designation as Scheduling Coordinator. (a)

Seller may terminate Buyer as Scheduling Coordinator: (i)

In accordance with Section 7(b) of this Exhibit G; or

(ii)

If Buyer materially fails to fulfill its obligations as Scheduling Coordinator and: (1)

Seller provides advance Notice to Buyer setting forth in reasonable detail the nature of such failure and such failure is not remedied within 30 days after such Notice; provided, however, that if such failure is not reasonably capable of being remedied within such 30day period, Buyer shall have such additional time (not to exceed

Exhibit G

Scheduling Coordinator Services

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

120 days) as is reasonably necessary to remedy such failure, so long as Buyer promptly commences and diligently pursues such remedy;

(iii)

(b)

(2)

Seller (A) submits to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the date of Buyer’s termination as Scheduling Coordinator, and (B) causes its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

(3)

The Parties will take any other action necessary to terminate the designation of Buyer as Scheduling Coordinator, including amending this Agreement; or

If Seller is required to elect Buyer as Scheduling Coordinator in accordance with Section 1.08, then, subject to Section 3.06(b) or 3.09(b), as applicable, by (1) providing a Notice to Buyer on or before the 60th day after Seller meets the requirements of Section 3.06(a) and 3.09(a), and (2) at least 30 days before the replacement Buyer as the Scheduling Coordinator, complying with the requirements for designating a different Scheduling Coordinator by taking all necessary actions to terminate the designation of Buyer as Scheduling Coordinator, including those actions set forth in Sections 7(b)(i) and (b)(ii) of this Exhibit G. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator.

At least 30 days before the expiration of the Term or as soon as an Early Termination Date is declared (regardless of which Party declared it), the Parties will take all actions necessary to terminate the designation of Buyer as Scheduling Coordinator as of 11:59 p.m. PPT on the Term End Date (“SC Replacement Date”). Such actions include the following: (i)

(ii)

Seller shall: (1)

Submit to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the SC Replacement Date; and

(2)

Cause its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

Buyer shall submit a letter to the CAISO resigning as Scheduling Coordinator effective as of the SC Replacement Date.

Exhibit G

Scheduling Coordinator Services

Page 4

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(c)

Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator. *** End of Exhibit G ***

Exhibit G

Scheduling Coordinator Services

Page 5

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT H [Intentionally omitted.] *** End of Exhibit H ***

Exhibit H

[Intentionally omitted.]

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT I Seller’s Forecasting Submittal and Accuracy Requirements 1.

2.

General Requirements. The Parties shall abide by the Forecasting requirements and procedures described below and shall agree upon reasonable changes to these requirements and procedures from time to time as necessary to: (a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the Operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated Forecast and outage submissions.

Seller’s Forecasting Submittal Requirements for all Generating Facilities. (a)

30-Day Forecast. No later than 30 days before the Term Start Date, Seller shall provide Buyer with a Forecast for the 30-day period commencing on the start of the Term using the Web Client. If the Web Client becomes unavailable, Seller shall provide Buyer with the Forecast by e-mail or by telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N. The Forecast, and any updated Forecasts provided pursuant to this Section 2, shall:

(b)

Exhibit I

(i)

Not include any anticipated or expected electric energy losses between the CAISO-Approved Meter and the Delivery Point; and

(ii)

Limit hour-to-hour Forecast changes to no less than 250 kWh during any period when the Web Client is unavailable. Seller shall have no restriction on hour-to-hour Forecast changes when the Web Client is available.

Weekly Update to 30-Day Forecast. Commencing on or before 5:00 p.m. PPT of the Wednesday before the first week covered by the Forecast provided pursuant to Section 2(a) of this Exhibit I, and on or before 5:00 p.m. PPT every Wednesday thereafter until the Term End Date, Seller shall update the Forecast for the 30-day period commencing on the Sunday following the weekly Wednesday Forecast update submission. Seller shall use the Web Client, if available, to supply this weekly update or, if the Web Client is not available, Seller shall provide Buyer with

Seller’s Forecasting Submittal and Accuracy Requirements

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

the weekly Forecast update by e-mailing or telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N. (c)

Further Update to 30-Day Forecast. As soon as reasonably practicable and commensurate with Seller’s knowledge, Seller shall provide Forecast updates related to Buyer’s Scheduled daily, hourly and real-time deliveries from the Generating Facility for any cause, including changes in Site ambient conditions, a Forced Outage, or a Real-Time Forced Outage, any of which results in a material change to the Generating Facility’s deliveries (whether in part or in whole). This updated Forecast pursuant to this Exhibit I must be submitted to Buyer via the Web Client by no later than: (i)

5:00 p.m. PPT on the day before the Trading Day impacted by the change, if the change is known to Seller at that time;

(ii)

The Hour-Ahead Scheduling Deadline, if the change is known to Seller at that time; or

(iii)

If the change is not known to Seller by the timeframes indicated in (i) or (ii) immediately above, no later than 20 minutes after Seller becomes aware of the event which caused the expected electric energy production change.

Seller’s updated Forecast must contain the following information: (w) The beginning date and time of the event resulting in the availability of the Generating Facility and expected electric energy production change;

3.

(x)

The expected ending date and time of the event:

(y)

The expected electric energy production, in MWh; and

(z)

Any other information required by the CAISO as communicated to Seller by Buyer.

Seller’s Forecasting Accuracy Requirements. If a (non-zero) Firm Contract Capacity quantity is applicable to this Agreement, then this Section 3 applies to Seller. (a)

Accuracy Metric. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate and report to Seller the monthly mean absolute error (“MAEm”) between Seller’s Day-Ahead Forecasts and the respective daily summations of Metered Energy: Forecast Error MAEm =

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Total Forecast n

Forecast Error =



| fi – ai |

i

n

Total Forecast =

 i

fi

where: n

= the total number of hours in calendar month “m”

i

= an hour within month “m”

fi = Seller’s Day-Ahead Forecast for hour “i” ai = the quantity of (i) Metered Energy for hour “i” plus the quantity of electric energy not delivered as a result of a Real-Time Forced Outage for hour “i” (in MWh) when the Generating Facility is not PIRP-eligible, or when Buyer is not Scheduling Coordinator; or (ii) the actual available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator. Buyer shall report each MAEm to Seller and, upon Seller’s request, Buyer shall furnish all supporting calculations within a reasonable timeframe. Notwithstanding anything to the contrary set forth in this Section 3(a), for hour “i” for which the absolute difference between variable “fi” and variable “ai” is a number greater than zero, to the extent that such difference results from the fault or negligence of Buyer in its role as Scheduling Coordinator the value “| fi – ai |” for that hour shall be deemed to be zero. (b) Forecasting Penalty. If the MAEm for a particular month “m” is greater than 15% or if the average Forecast error for all hours of the month is greater thenthan three MW, then an “MAE Failure” will be deemed to have occurred. An MAE Failure will be waived if Seller demonstrates to Buyer’s reasonable satisfaction that the MAE Failure was the result of unexpected changes in either electrical or steam demand associated with the Site Host Load. If such MAE Failure has been waived, then that month does not count as a month in which there was an MAE Failure. For each month in which an MAE Failure has occurred, Seller shall pay a fee equal to the applicable Monthly Scheduling Fee in addition to any otherwise applicable Monthly Scheduling Fee.

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

During each month an MAE Failure occurs, subject to the limitations of the following paragraph, Seller will continue to receive Monthly Capacity Payments for the Firm Contract Capacity based on the Firm Capacity Price and capacity payment calculations for firm capacity as set forth in Section 3 of Exhibit D. If, however, an MAE Failure occurs three times in any rolling 12-month period, then starting on the first day of the calendar month immediately following the third such occurrence (such month, the “First Penalty Month”): (i)

The quantity of Firm Contract Capacity specified in Section 1.02(d) will be deemed to be zero (“Penalized Firm Contract Capacity”); and

(ii)

The quantity of As-Available Contract Capacity specified in Section 1.02(d) will be deemed increased by the quantity of Firm Contract Capacity as such quantity existed before the First Penalty Month (“Penalized As-Available Contract Capacity”).

The Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall continue to be in effect during every subsequent calendar month until there are two consecutive calendar months without an MAE Failure (including a month in which an MAE Failure has been waived). Upon such event, starting on the first day of the calendar month immediately following the second consecutive month during which Buyer does not have an MAE Failure, the Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall revert to the Firm Contract Capacity and AsAvailable Contract Capacity quantities existing before the First Penalty Month. *** End of Exhibit I ***

Exhibit I

Seller’s Forecasting Submittal and Accuracy Requirements

Page 4

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT J CAISO Charges If at any time after the Term Start Date Buyer is not Scheduling Coordinator for the Generating Facility, then Buyer will not be responsible for any CAISO Charges. If at any time after the Term Start Date Buyer is Scheduling Coordinator for the Generating Facility, then Buyer shall pay all CAISO Charges and receive all CAISO Revenues; provided, however, if at any time after the Term Start Date: 1.

The CAISO implements or has implemented any sanction or penalty related to Scheduling, outage reporting or generator Operation, and any such sanctions or penalties are imposed on the Generating Facility or to Buyer as Scheduling Coordinator for the Generating Facility due solely to the actions or inactions of Seller, then such sanctions or penalties will be Seller’s responsibility;

2.

Seller or any third party dispatches any portion of the Net Contract Capacity for the benefit of any party other than Buyer or a Site host in respect of the Host Site, then Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator);

3.

Seller does not comply with: (a)

The requirements set forth in Section 3.15; or

(b)

Seller’s obligation associated with any CAISO or Transmission Provider notice or instruction (as may be communicated by Buyer as Scheduling Coordinator) to (i) increase output to the Firm Contract Capacity during a System Emergency or an Emergency Condition, or (ii) reschedule a planned outage set to occur during a System Emergency or an Emergency Condition, then

Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges associated with any failure set forth in Sections 3(a) or 3(b) of this Exhibit J (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator); or 4.

If the Generating Facility is PIRP-eligible and is not certified as a PIRP resource for any reason, then Seller shall indemnify, defend, and hold Buyer harmless against all CAISO Charges associated with the electric energy generated and delivered from the Generating Facility.

If any of Sections 1 through 4 of this Exhibit J apply and the Generating Facility is subject to an Uninstructed Deviation Penalty, Seller will not be required to pay the SDD Energy Adjustment and, instead, shall be responsible for all applicable Uninstructed Deviation Penalty charges for the Generating Facility.

Exhibit J

CASIO Charges

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

*** End of Exhibit J ***

Exhibit J

CASIO Charges

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT K Scheduling and Delivery Deviation Adjustments If Buyer is Scheduling Coordinator for the Generating Facility and if the Generating Facility is not PIRP-eligible, then Seller or Buyer, as the case may be, shall be responsible for the following SDD Adjustments with respect to the Generating Facility: 1.

SDD Energy Adjustment. An Adjustment will be calculated for each Settlement Interval in a month if the Metered Energy is either (a) less than the Performance Tolerance Band Lower Limit in any Settlement Interval or (b) greater than the Performance Tolerance Band Upper Limit in any Settlement Interval. When the SDD Energy Adjustment is negative, Seller shall make a payment to Buyer and when the SDD Energy Adjustment is positive, Seller shall receive a credit from Buyer. The SDD Energy Adjustment is calculated as follows: If A < D, then SDD Energy Adjustment= (D – A) x (EP – P) or If A > E, then SDD Energy Adjustment = (A – E) x (P – EP) Otherwise, the SDD Energy Adjustment = 0 where: A = Metered Energy for the Settlement Interval; B = Seller’s Final Energy Forecast based on the hourly forecasts made pursuant to Exhibit I corresponding to the Settlement Interval; C = Performance Tolerance Band = The greater of (a) three percent of the Seller’s Final Energy Forecast divided by the number of Settlement Intervals in such hour or (b) one (1) MWh divided by the number of Settlement Intervals in such hour; D = Performance Tolerance Band Lower Limit = (B – C); E = Performance Tolerance Band Upper Limit = (B + C); EP =

TOD Period Energy Price applicable to the Settlement Interval specified in Section 2(b) of Exhibit D; and

Exhibit K

Scheduling and Delivery Deviation Adjustments

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

P = Real-Time Price for the Generator’s PNode as published by the CAISO on OASIS for the Settlement Interval. 2.

SDD Administrative Charge. Seller shall make a payment to Buyer (the “SDD Administrative Charge”) for each Settlement Interval in a month if Metered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, in any Settlement Interval. The SDD Administrative Charge is calculated as follows: If A > (B + C) or A < (B – C), then: SDD Administrative Charge = (Absolute Value (B – A) – C) x Uninstructed Deviation GMC Rate. Otherwise, the SDD Administrative Charge = 0. *** End of Exhibit K ***

Exhibit K

Scheduling and Delivery Deviation Adjustments

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT L Physical Trade Settlement Amount This Exhibit L is only applicable when Buyer is not Scheduling Coordinator. 1.

Physical Trades Cleared in the IFM. The CAISO Revenue credited to Buyer’s account by CAISO as a result of a Physical Trade having cleared in the IFM shall be for Buyer’s account.

2.

Physical Trades not Cleared in the IFM. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate the Physical Trade Settlement Amount (“PTSAi”) for each hour as follows: PTSAi =

CPTi x (CPTPi – PNodei)

Where: i

=

an hour within month “m”

CPT

=

Converted Physical Trade, in MWh

CPTP

=

Converted Physical Trade Price, and

PNode

=

the Generating Facility’s PNode price, in dollars per MWh.

If the PTSAi is positive and Seller submitted the original Physical Trade in accordance with Section 3.14(s)(ii) and Exhibit I, then Buyer shall owe Seller the PTSAm for month m. In any event the PTSAi is negative, however, then Seller shall owe Buyer the PTSAi. *** End of Exhibit L ***

Exhibit L

Physical Trade Settlement Amount

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT M SC Trade Settlement Amount This Exhibit M is only applicable when Buyer is not Scheduling Coordinator. If, in any Settlement Interval, a Generating Facility’s Scheduled Amount differs from the Generating Facility’s Metered Energy by more than the SC Trade Tolerance Band, then Seller shall be subject to a payment adjustment calculated by Buyer in accordance with the procedures and formulas set forth below. (1)

Under-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy, and the Real-Time Price is greater than the DayAhead Price payable during the Settlement Interval, then Seller’s monthly payment amount shall be reduced by each Under-Scheduling Settlement Interval Adjustment Amount calculated by the following formula: UNDER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [A – B] x [D – C] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No under-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy if, during such Settlement Interval, the Real-Time Price is equal to or less than the Day-Ahead Price payable during the Settlement Interval. (2)

Over-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy, and the Real-Time Price is less than the DayAhead Price payable during the Settlement Interval; Then Seller’s monthly payment amount shall be reduced by each Over-Scheduling Settlement Interval Adjustment Amount calculated by the following formula:

Exhibit M

SC Trade Settlement Amount

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

OVER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [B – A] x [C – D] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No over-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy if, during such Settlement Interval, the Real-Time Price is greater than or equal to the Day-Ahead Price payable during the Settlement Interval. *** End of Exhibit M ***

Exhibit M

SC Trade Settlement Amount

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT N Notice List [SELLER’S NAME] KERN RIVER COGENERATION COMPANY

[BUYER’S NAME] SOUTHERN CALIFORNIA EDISON COMPANY

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

Contract Sponsor: Attn: Executive Director Street: P.O. Box 80478 City: Bakersfield, California 93380 Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Reference Numbers: Duns: 17-357-0292 Federal Tax ID Number: 95-3880295

Contract Sponsor: Attn: Vice President of Renewable and Alternative Power Street: 2244 Walnut Grove Avenue City: Rosemead, California 91770 Phone: Facsimile: Reference Numbers: Duns: 006908818 Federal Tax ID Number: 95-1240335

Contract Administration: Attn: Business Manager Phone: (661) 615-4675 Facsimile: (661) 615-4610 E-mail: [email protected]

Contract Administration: Attn: Phone: Facsimile: E-mail:

Forecasting: Attn: Control Room Phone: (661) 615-4639 Facsimile: (661) 615-4623 E-mail: [email protected]

Forecasting: Attn: Phone: 626.307.4420 Facsimile: E-mail: [email protected]

Day-Ahead Forecasting: Phone: (661) 615-4639 Facsimile: (661) 615-4623 E-mail: [email protected]

Day-Ahead Scheduling: Attn: Manager of Day-Ahead Operations Attn: Scheduling Desk Phone: 626.307.4425 or 626.307.4420 Facsimile: 626.307.4413 E-mail: [email protected] Real-Time Scheduling: Attn: Manager of Real-Time Operations Attn: Operations Desk Phone: 626.307.4405 or 626.307.4453 Facsimile: 626.307.4416 E-mail: [email protected]

Real-Time Forecasting: Phone: (661) 615-4639 Facsimile: (661) 615-4623 E-mail: [email protected]

Exhibit N

Notice List

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Payment Statements: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] CAISO Charges and CAISO Sanctions: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Payments: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Wire Transfer: BNK: Chase Manhattan ABA: 021-0000-21 ACCT: 910-2588-697 Credit and Collections: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Guarantor: N/A Attn: Phone: Facsimile: E-mail: Lender: N/A Attn: Phone: Facsimile: E-mail:

Exhibit N

Payment Statements: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: CAISO Charges and CAISO Sanctions: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Payments: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Wire Transfer: BNK: JP Morgan Chase Bank ABA: 021000021 ACCT: 323-394434 Credit and Collateral: Attn: Manager of Credit and Collateral Phone: Facsimile: Email: With additional Notices of an Event of Default or Potential Event of Default to: Attn: Manager SCE Law Department Power Procurement Section Phone: Facsimile: Email: Guarantor: N/A Attn: Phone: Facsimile: E-mail: Lender: N/A Attn: Phone: Facsimile: E-mail:

Notice List

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

*** End of Exhibit N ***

Exhibit N

Notice List

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT O [Intentionally omitted.] *** End of Exhibit O ***

Exhibit O

[Intentionally omitted.]

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT P [Intentionally omitted.] *** End of Exhibit P ***

Exhibit P

[Intentionally omitted.]

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT Q [Intentionally omitted.] *** End of Exhibit Q ***

Exhibit Q

[Intentionally omitted.]

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT R Outage Schedule Submittal Requirements 1.

General Requirements. The Parties shall abide by the Outage Schedule Submittal Requirements described below and shall agree upon reasonable changes to these requirements and procedures from time to time, as necessary to:

2.

(a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated forecast and outage submissions.

Seller’s Availability Forecasting Submittal Requirements for all Generating Facilities. Seller shall submit maintenance and planned outage schedules in accordance with the following schedule: (a)

No later than January 1st, April 1st, July 1st and October 1st of each Term Year, and at least 60 days before Parallel Operationthe Term Start Date, Seller shall submit to Buyer its schedule of proposed planned outages (“Outage Schedule”) for the subsequent twenty four-month period using a Buyer-provided web-based system or an e-mail address designated by Buyer (“Web Client”).

(b)

Seller shall provide the following information for each proposed planned outage: (i)

Start date and time;

(ii)

End date and time; and

(iii)

Capacity online, in MW, during the planned outage.

(c)

Within 20 Business Days after Buyer’s receipt of an Outage Schedule, Buyer shall notify Seller in writing of any request for changes to the Outage Schedule, and Seller shall, consistent with Prudent Electrical Practices, accommodate Buyer’s requests regarding the timing of any planned outage.

(d)

Seller shall cooperate with Buyer to arrange and coordinate all Outage Schedules with the CAISO.

Exhibit R

Outage Schedule Submittal Requirements

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

(e)

In the event a condition occurs at the Generating Facility which causes Seller to revise its planned outages, Seller shall provide Notice to Buyer, using the Web Client, of such change (including, an estimate of the length of such planned outage) as required in the CAISO Tariff after the condition causing the change becomes known to Seller.

(f)

Seller shall promptly prepare and provide to Buyer upon request, using the Web Client, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code, the CAISO Tariff or any Applicable Law mandating the reporting by investor owned utilities of expected or experienced outages by electric energy generating facilities under contract to supply electric energy. *** End of Exhibit R ***

Exhibit R

Outage Schedule Submittal Requirements

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT S TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements Introduction. Subject to Section 4.04 and Exhibit D, this Exhibit S sets forth the formulas and methodology that Buyer will use in order to calculate the TOD Period Energy Price, and also sets forth Seller’s Greenhouse Gas emissions reporting requirements. 1. TOD Period Energy Price. Subject to Section 2 of this Exhibit S, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable time-period in accordance with the following formula: TOD Period Energy Price $/kWh = ((Applicable HR * BTGP/1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = The Heat Rate for the specified time-period, per the following table: Calendar Year(s) 2011 2012 January 1, 2013 through December 31, 2014 January 1, 2015 until the termination of this Agreement

Heat Rate (Btu/kWh) 8,700 8,225 8,125 Market Heat Rate

BTGP = Calendar month Burner Tip Gas Price ($/MMBtu), per the Decision and CPUC Resolution E-4246; VOM = Calendar month avoided variable O&M ($/kWh), per the Decision and CPUC Resolution E-4246; GHG Charges = All taxes, charges or fees assessed with the implementation and regulation of Greenhouse Gas emissions with respect to the Generating Facility imposed by any Governmental Authority, such as the CARB’s AB 32 Cost of Implementation Fee (as defined in Title 17 C.C.R. §95200). For example, if the charges are assessed on but not included in fuel consumption or gas costs, the Applicable HR or Burner Tip Gas Price will be used to derive the dollars per kilowatt-hour charge. On January 1, 2015 or the commencement of the First Compliance Period, the GHG Charges will equal zero in the above formula; TOU (i.e., time-of-use) = The TOU factors are as follows: Summer Winter Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Peak Partial-Peak Off-Peak Super Off-Peak

1.2564 1.1535 0.9155 0.7439

N/A 1.1395 0.9628 0.8216

Buyer may update the TOU factors set forth above at the beginning of each calendar year using the electric energy-only portion of the time-of-use factors (as adjusted by Buyer, if necessary, to reflect Buyer’s CPUC-approved time-of-use periods) set forth in Buyer’s most recent RPS Program solicitation (e.g., 2012 time-of-use factors are those used in Buyer’s 2011 RPS Program solicitation). Off-Peak TOU factors will be calculated as a residual – similar to the current method – to preserve the correctness of the monthly hourly weighting. An example for Period A – Summer is: [Number of hours in month - (1.2564 * Number of Summer Peak hours in Month) - (1.1535 * Number of Summer Partial-Peak hours in Month) - (0.7439 * Number of Summer Super Off-Peak hours in Month)] / Number of Summer Off-Peak hours in Month {Buyer Comment: These TOU factors are only applicable if Buyer is PG&E, in which case, the TOU variable and factors for SCE and SDG&E (below) must be deleted.}

TOU (i.e., time-of-use) = Throughout the Term, the applicable time-of-use factors are as follows: On-Peak Mid-Peak Off-Peak Super Off-Peak

Summer 1.4251 see below 0.8526 N/A

Winter N/A 1.2185 see below 0.7760

Summer Mid-Peak = (Total # hours in month - (1.4251 * # of Summer On-Peak hours in month) - (0.8526 * # of Summer Off-Peak hours in month)) / # of Summer Mid-Peak hours in month Winter Off-Peak = (Total # hours in month - (1.2185 * # of Winter Mid-Peak hours in month) - (0.7760 * # of Winter Super Off Peak hours in month)) / # of Winter Off-Peak hours in month {Buyer Comment: These TOU factors are only applicable if Buyer is SCE, in which case, the TOU variable and factors for PG&E (above) and SDG&E (below) must be deleted.}

TOU (i.e., time-of-use) = The TOU factors are as follows:

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 2

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

On-Peak Semi-Peak Off-Peak Super Off-Peak

Summer 1.411 1.106 0.986 0.645

Winter 1.224 1.106 0.933 0.711

Buyer may update the TOU factors set forth above at the beginning of each calendar year using the electric energy-only portion of the time-of-use factors (as adjusted by Buyer, if necessary, to reflect Buyer’s CPUC-approved time-of-use periods) set forth in Buyer’s most recent RPS Program solicitation (e.g., 2012 time-of-use factors are those used in Buyer’s 2011 RPS Program solicitation). {Buyer Comment: These TOU factors are only applicable if Buyer is SDG&E, in which case, the TOU variable and factors for SCE and PG&E (above) should be deleted.}

LA (i.e., hourly location adjustment, in $/kWh) = LMPQF - LMPTrading Hub Where the hourly location adjustment (i.e., LA) will be based on the hourly Day-Ahead prices and actual hourly generation by the Generating Facility for delivery to Buyer as follows: LMPQF (in $/kWh) = The hourly Day-Ahead Locational Marginal Price at the point of interconnection with the CAISO Controlled Grid associated with the Generating Facility; and LMPTrading Hub (in $/kWh) = The hourly Day-Ahead Locational Marginal Price of the trading hub where the Generating Facility is located (i.e., SP15 Existing Zone Generation Trading Hub (formerly SP15), NP15 Existing Zone Generation Trading Hub (formerly NP15), or ZP26 Existing Zone Generation Trading Hub (formerly ZP26), as applicable, or any successor thereto). 2. TOD Period Energy Price during the Floor Test Term. (a) If there is a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), then, during the Floor Test Term, the TOD Period Energy Price will be the higher of the following two formulas (the “GHG Floor Test”): (i) TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 3

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A; BTGP ($/MMBtu) = As set forth above; VOM ($/kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. OR (ii) TOD Period Energy Price $/kWh = ((Applicable HR * (BTGP + GHG Allowance Price) /1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = (A) 8,225 Btu/kWh through December 31, 2012; (B) 8,125 Btu/kWh from January 1, 2013 through December 31, 2014; and (C) Actual HR from January 1, 2015 until the end of the Floor Test Term; BTGP ($/MMBtu) = As set forth above; GHG Allowance Price ($/MMBtu) = Allowance Cost ($/MT) * 117lbs of Greenhouse Gas per MMBtu / 2,204.6 lbs per MT Where: Allowance Cost ($/MT) = The cost of one Allowance, determined using the GHG Auction clearing price from the latest GHG Auction that has taken place during the calendar quarter immediately preceding the date that Buyer’s payment is due to Seller; provided, however, that if there is no GHG Auction held during the applicable time-period, then the Allowance Cost is determined in accordance with Section 2(c) of this Exhibit S; VOM ($/kWh) = As set forth above;

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 4

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

GHG Charges ($/kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. (b) Free Allowance Reporting and Allocation. If, at any time, Buyer makes a monthly payment to Seller utilizing the GHG Floor Test formula set forth in Section 2(a)(ii) of this Exhibit S, then Buyer shall deduct from the monthly payment to Seller for the applicable month the value of the Free Allowances disclosed in and based on all Free Allowance Notices that have not already been applied to a prior payment to Seller; provided, however, that if Buyer, using reasonable efforts, is unable to process such payment adjustment for the applicable month, then Buyer shall make such payment adjustment to the next monthly payment due to Seller. For any month that Buyer utilizes the formula set forth in Section 2(a)(ii) of this Exhibit S to make a monthly payment to Seller, Buyer shall maintain a record of the value and quantity of all Free Allowances disclosed in the Free Allowance Notices, if any, and shall deduct the value of such Free Allowances to any subsequent monthly payment due to Seller where Buyer calculates such monthly payment utilizing the formula set forth in Section (2)(a)(ii) of this Exhibit S until such time that the value of all such Free Allowances are expended. In order for Buyer to make the payment adjustment set forth in the immediately preceding paragraph, Seller agrees to deliver to Buyer, within twenty (20) days of receiving any Free Allowances, a Free Allowance Notice for the applicable month, which Free Allowance Notice must include all Additional GHG Documentation. Buyer shall value any such Free Allowances using the same methodology Buyer uses in valuing the Allowance Cost, as set forth above. (c) Determining Allowance Costs under the GHG Floor Test if there is No GHG Auction. This Section 2(c) is applicable if no GHG Auction has been held during the time-period for which the Allowance Cost variable set forth in Section 2(a) of this Exhibit S is to be determined. In such an instance, publicly available indices will be used to determine the price for the applicable period. If no such indices exist, Buyer will meet with the Trade Organizations to negotiate in good faith to reach an agreement on setting the Allowance Cost variable. If, after negotiating for fifteen (15) Business Days, Buyer and the Trade Organizations have not reached an agreement on setting the Allowance Cost variable, then Buyer and the Trade Organizations shall each select, within fifteen (15) days after such failed negotiations, price quotations for the cost of one Allowance, as set forth in two (2) different Reference Market-Makers, for a total of four (4) price quotations. The Allowance Cost variable for the applicable time-period will be determined by taking the average of the four (4) price quotations so selected by Buyer and the Trade Organizations. Seller agrees and acknowledges that it shall be bound by any agreement as to the

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 5

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Allowance Cost variable between Buyer and the Trade Organizations, in accordance with the foregoing. (d) TOD Period Energy Price from the end of the Floor Test Term. As of end of the Floor Test Term until the termination of this Agreement, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable timeperiod in accordance with the following formula: TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A; BTGP ($/MMBtu) = As set forth above; VOM ($kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. (e) Seller’s Responsibility. Other than Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges as set forth in payment formulas above, Seller is solely responsible for all GHG Compliance Costs and all other costs associated with implementation and regulation of GHG emissions with respect to Seller or the Generating Facility. 3. Reporting Requirements. (a) From the Effective Date through the Term End Date (and for any period following the termination of this Agreement to the extent relating back to the Term), Seller shall provide to Buyer the following information (together, the “Annual GHG Reports”): (i) On or before the fifth (5th) Business Day following Seller’s timely submission to the CARB (or any other authorized Governmental Authority having jurisdiction in California) of the CARB Mandatory GHG Emissions Annual Report, or such other Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 6

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

annual report submitted to the CARB, detailing the Greenhouse Gas emissions of the Generating Facility for the applicable calendar year (as verified by an independent third party, if applicable) (the “CARB Annual Report”), Seller shall deliver such CARB Annual Report to Buyer; and (ii) To the extent not set forth in the CARB Annual Report (or if Seller is no longer required to submit the CARB Annual Report for any reason), then Seller shall submit to Buyer, along with the CARB Annual Report (or, if Seller is no longer required to submit the CARB Annual Report for any reason, then on the sixtieth (60th) Business Day following the end of the applicable calendar year), the following information for the applicable calendar year, which, in each case, must be verifiable and of settlement quality: (1) the Useful Thermal Energy Output of the Generating Facility; and (2) total fuel usage of the Generating Facility; and (3) the total amount of Greenhouse Gas emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, and the Useful Thermal Energy Output of the Generating Facility; and (4) the total electric energy produced by the Generating Facility, the electric energy used to serve the Site Host Load, and the electric energy delivered to Buyer; and (5) the number of Allowances (including Free Allowances) held or surrendered by Seller for such calendar year during any period where the TOD Period Energy Price is calculated based on the GHG Floor Test. (b) If Buyer requires any other information not delineated in Section 3(a) of this Exhibit S in order to comply with any Greenhouse Gas emissions reporting requirements adopted by the CARB or by any other Governmental Authority and imposed on Buyer (other than the information that Seller must provide in accordance with Section 3(c) of this Exhibit S), then Buyer shall promptly meet and confer with the Trade Organizations regarding such other information that Buyer requires and negotiate in good faith to reach a mutually acceptable agreement. Seller agrees and acknowledges that it shall be bound by any agreement between Buyer and the Trade Organizations, in accordance with the foregoing. (c) Buyer will review the Annual GHG Reports described in this Section 3 to determine if there is any discrepancy in the payments made by Buyer to Seller for GHG Compliance Costs during the course of the applicable calendar year. To the extent Buyer determines that there is any such discrepancy, (i) if Buyer owes Seller an additional payment for GHG Compliance Costs, then Buyer shall make such additional payment in a subsequent monthly payment to Seller under this Agreement, or (ii) if Seller owes Buyer a payment refund for GHG Compliance Costs, then Buyer shall offset such payment refund amount in a subsequent monthly payment to Seller under this Agreement. If this Agreement terminates before Buyer is able to make such additional payment for GHG Compliance

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 7

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

Costs or offset such GHG Compliance Costs payment refund from Seller’s monthly payments, as applicable, then Buyer or Seller, as applicable, shall pay all remaining payment amounts due within the thirty- (30) day period after the termination of this Agreement. (d) To the extent that the information provided by the disclosing Party in accordance with this Section 3 is Confidential Information, the receiving Party shall treat such Confidential Information with the same degree of care that it currently treats the data and information provided by Qualifying Cogeneration Facilities under the existing Qualifying Cogeneration Facilities monitoring compliance program. 4. Market Disruption Event. Unless this Agreement has terminated, if, on or after the date that the Market Heat Rate applies to and is used in the calculation of the TOD Period Energy Price and until the termination of this Agreement, there occurs a Market Disruption Event, then the Market Heat Rate for the affected Trading Day(s) must be determined by reference to the Market Heat Rate for the first Trading Day thereafter on which no Market Disruption Event exists; provided, however, that if the Market Heat Rate is not so determined within five (5) Trading Days after the Market Disruption Event occurred or existed, then Buyer shall meet with the Trade Organizations to negotiate in good faith to reach an agreement on a Market Heat Rate (or a method for determining a Market Heat Rate), and if Buyer and the Trade Organizations have not so agreed on or before the twelfth (12th) Trading Day after which the Market Disruption Event occurred or existed, then the Market Heat Rate will be determined in good faith by taking the average of the price quotations for electric energy and relevant Trading Days that are obtained from no more than two (2) Reference Market-Makers selected by each of Buyer and the Trade Organizations (for a total of four (4) price quotations). Seller hereby agrees and acknowledges that it shall be bound by any agreement as to a Market Heat Rate (or a method for determining a Market Heat Rate) between Buyer and the Trade Organizations, in accordance with the foregoing. *** End of Exhibit S ***

Exhibit S

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 8

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company

EXHIBIT T QF Efficiency Monitoring Program – Cogeneration Data Reporting Form [Buyer’s address] Buyer’s telephone number and email address] 2244 Walnut Grove Ave, Rosemead, CA 91770 QF Efficiency Monitoring Program Administrator, (626) 302-9110 [email protected] [PrevYear] I.

Name and Address of Project Name: Street: City: ID No.: ________

II. In Operation: Yes

State:

Zip Code:

Generation Nameplate (KW): __________________ No

III. Can your facility dump your thermal output directly to the environment?

Yes

No

IV. Ownership Ownership

Name

Address

(%)

1 2 3 4 5

Utility Y N Y N Y N Y N Y N

V. [PrevYear] Monthly Operating Data



Indicate the unit of measure used for your useful thermal output if other than mBTUs: BTUs Therms mmBTUs



If Energy Input is natural gas, use the Lower Heating Value (LHV) as supplied by Gas Supplier. Useful Power Output (kWh)

Energy Input (Therms)

Useful Thermal Output (mBtu)

JAN Feb Mar Apr May Jun Jul Aug Sep Oct

Exhibit T Form

QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

Southern California Edison ID #[Number], [Seller’s Name] RAP ID #2811, Kern River Cogeneration Company Nov Dec Yearly Total

*** End of Exhibit T ***

Exhibit T Form

QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

Document comparison by Workshare Professional on Monday, December 10, 2012 9:15:00 AM Input: Document 1 ID Description

Document 2 ID

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file://\\sce.eix.com\workgroup\CorpCtr4\RAP\RAP Contract Origination\CHP Program\Contract Application Forms\~Settlement PPAs\Transition PPA\Transition PPA [10-8-2010 - Final].doc Transition PPA [10-8-2010 - Final] file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\Transition Contract Applications\2801 & 2058 - KRCC & Sycamore\Subsequent PPAs\Posting for Approval\20121012\KRCC Contract\20121012 KRCC Transition PPA.DOC 20121012 KRCC Transition PPA standard

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN [Click here to enter Counterparty.]KERN RIVER COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY

This confirmation letter and the appendices attached hereto and incorporated herein (“Confirmation”) confirms the Transaction between [Counterparty]Kern River Cogeneration Company (“Seller” or “[Shortname]Kern River”) and Southern California Edison Company (“Buyer” or “SCE”) dated as of [Date]October 15, 2012 (“Confirmation Effective Date”) regarding the sale and purchase of the Product, as such term is defined below in Section 1.5, in accordance with and subject to the terms and provisions of this Confirmation, the EEI Master Power Purchase & Sale Agreement, together with the Cover Sheet (the “Transition Cover Sheet”), any amendments and annexes thereto between Seller and SCE dated as of [Date] (“October 15, 2012 (“Transition Master Agreement”), and Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement.” Capitalized terms used but not defined in this Confirmation shall have the meanings ascribed to them in the Transition EEI Agreement or the Tariff. If any term in this Agreement conflicts with the Tariff, the definition set forth in this Agreement shall supersede. RECITALS A.

Seller owns and operates Generating Unit # 1 and Generating Unit # 3, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement.

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement.

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition RA Confirmation and the Transition PPA. ARTICLE 1 TRANSACTION DEFINITIONS

1.1

Seller

[Counterparty].Kern River Cogeneration Company. 1.2

Buyer

SCE. 1.3

Term

The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied; provided, however, that: (i) before the commencement of the Delivery Period, SCE must have obtained, in its sole discretion or waived, CPUC Approval, and (ii) before the commencement of the Delivery Period must commence within 24 months of the Confirmation Effective Date, FERC Approval as set forth in the

1

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Transition PPA must have been obtained. 1.4

Delivery Period

The Delivery Period shall be as set forth in Appendix 3.1(a) unless terminated earlier“Delivery Period” commences on the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained; provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition PPA and Transition RA Confirmation have been satisfied or waived in accordance with the terms of this Agreement.and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), and ends June 30, 2015. 1.5

Product

Capacity, Energy, Ancillary Services, and any other product derived from or associated with each Generating Unit, including any Green Attributes associated with the Capacity, Energy and Ancillary Services [that are in excess of the Green Attributes used, or retained for future use, by Seller or a Site Host, both in connection with the Host Site to meet a known or established, at the point in time when the Green Attributes are to be used or retained, obligation under applicable law] (collectively, the “Product”). During the Delivery Period, Seller shall sell and deliver, and SCE shall purchase and receive, the Product, subject to the terms and conditions of this Confirmation.; provided, however, that Seller’s Allowances shall be treated in accordance with Article 20. Seller represents, warrants, and covenants that it will deliver the Product to SCE free and clear of all liens, security interests, claims, and encumbrances. Seller shall not substitute or purchase the Product or any portion of the Product from any other generating resource or from the market for delivery hereunder. [SCE Internal Comment: use bracketed language for facilities with host load (i.e., hybrids).] 1.6

Energy Delivery Point

The Energy Delivery Point shall be as described and set forth in the single-line diagram of grid interconnection attached hereto as Appendix 1.6. Except as otherwise set forth in this Confirmation, Seller shall be responsible for all charges and penalties associated with the operation of the Generating Units and transmission of Energy up to and including the Energy Delivery Point, and SCE shall be responsible for all charges and penalties associated with receiving and transmitting Energy after and from the Energy Delivery Point. Title, possession, and risk of loss related to Energy shall transfer from Seller to SCE after the Energy Delivery Point. In the event of a failure by Seller to deliver the Product to the Energy Delivery Point, Article Four of the Transition Master Agreement shall not apply. The Energy Delivery Point specified herein is the Product’s “Delivery Point” for this Transaction for purposes of the Transition EEI Agreement. 1.7

Intentionally deleted.Deleted

1.8

Generating Units

Each Generating Unit and its applicable description are set forth in Section A and Section B of Appendix 1.8. 1.9

No Change to Other Agreements

Notwithstanding anything to the contrary in this Confirmation, Seller acknowledges and agrees that and SCE each acknowledge and agree that with respect to the Generating Units which are subject to the obligations under the Agreement, the Transition RA Confirmation and the Transition PPA, any other agreement between itSeller and SCE, including any interconnection agreement, is separate and apart from thisthe Agreement, the Transition RA Confirmation and the Transition PPA, such that no other agreement shall modify or add to the Parties’ obligations under the Transition EEI Agreement or this Confirmation, and that no Party’s breach under such other agreement shall excuse a Party’s nonperformance under the Agreement, except as otherwise specifically provided for under this AgreementConfirmation.

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

ARTICLE 2 PURCHASE AND SALE OF PRODUCT 2.1

Exclusivity

During the Delivery Period, SCE shall have the exclusive right to the Product purchased by SCE hereunder, and all benefits derived therefrom, including the exclusive right to use, market, or sellresell the Product (or any portion thereof) purchased hereunder and the right to all revenues generated from the use, saleresale, or marketing of such Product, and Seller may not sell, assign, or otherwise transfer, or commit to sell, assign, or otherwise transfer, the Product (or any portion thereof) or any benefits derived therefrom, to any party other than SCE. In addition, SCE shall have the ability to dispatch each Generating Unit to its PMax at the instruction of the CAISO and subject to the Operating Restrictions applicable to such Generating Unit and shall be entitled to all benefits of such dispatch including all revenues associated with such capacity, energy or ancillary services up to and including the Generating Unit’s PMax. 2.2

Ownership

Seller shall maintain ownership of, and exclusive demonstrable rights to, each of the Generating Units throughout the Term. ARTICLE 3 COMPENSATION AND AVAILABILITY 3.1

Compensation (a)

Monthly Capacity Payment: For each Generating Unit, SCE shall make the Monthly Capacity Payment, payable in arrears, to Seller. The Monthly Capacity Payment for each month of the Delivery Period is set forth in Section C of Appendix 3.1(a), and is subject to reduction in accordance with this Confirmation, including Sections 3.2 and 3.3 below. If the Monthly Capacity Payment is reduced in accordance with this Confirmation, SCE shall make the Reduced Monthly Capacity Payment in lieu of the Monthly Capacity Payment.

(b)

Variable O&M Payment: SCE shall pay Seller a monthly Variable O&M Payment, calculated as follows: n

Variable O&M Paymentm = Variable O&M Chargey * where:

 i

Qualifying Delivered Energyi

Variable O&M Chargey is set forth in Appendix 3.1(b) m = the relevant month within the Delivery Period being calculated y = the Contract Year corresponding to month “m” n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m”

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

(c)

Start-Up Charge: SCE shall pay for the Start-Up Fuel, the Start-Up Charge and the Start-Up Aux Charge for each Start-Up unless specified otherwise in this Confirmation. In addition to all Energy produced after a Start-Up, all Energy produced prior to the Generating Unit achieving a Start-Up during the respective start-up cycle shall be for SCE’s account.

(d)

(i)

If SCE aborts a start-up before the Generating Unit achieves full Start-Up, then SCE shall [a] pay for any natural gas consumed by the Generating Unit in connection with such aborted start-up, up to the applicable quantity of the Start-Up Fuel, [b] pay the Start-Up Charge and [c] pay the portion of the Start-Up Aux Charge that is proportional to [i] the amount of Start-Up Aux Energy (MWh) required from the beginning of the Start-Up to the time when such Start-Up was aborted as compared to [ii] the applicable Start-Up Time, provided that such payment shall not exceed the applicable Start-Up Aux Charge.

(ii)

If theany Generating Unit is unable to generate or deliver Energy to the Energy Delivery Point after a Start-Up, but before the next scheduled shutdown of thesuch Generating Unit for any reason other than a Force Majeure, SCE is not responsible for any charges under this Section 3.1(c) associated with the next Start-Up.

Transition Costs: SCE shall compensate Seller for the Transition Fuel and pay the applicable Transition Cost for each MSG Transition unless specified otherwise in this Confirmation. All Energy produced by the Generating Unit during the respective transition shall be for SCE’s account. Compensation for Transition Fuel will be included in the Fuel Payment.(e) Fuel Payment: SCE shall pay to Seller a “Fuel Payment” equal to the sum of all Gas Commodity Costs, as defined in 3.1(ed)(vi) below, for all applicable calendar days during a calendar month during the Delivery Period plus all Transport Costs, if any, for the applicable calendar month. For purposes of calculating the Fuel Payment, the following definitions shall be used: (i)

Gas Index: The index price expressed in $/MMBTUMMBtu for the applicable flow date published by Platts Gas Daily (in the internet publication currently accessed through www.platts.com) in the table entitled “Daily price survey” under the heading “Citygates” for “Kern River, delivered” under the column “Midpoint” for “SoCalGas Citygate”plus $0.01/MMBtu. For the purposes of calculating the Fuel Payment, the Gas Index will be applied to Settlement Intervals on a calendar day basis with each day starting at hour ending 01:00 and not on a Gas Day basis. If the Gas Index ceases to be published, the Parties agree to deem the loss of the Gas Index a “Market Disruption Event” as defined in the Transition Master Agreement and follow the provisions outlined in Section 3.4 of the Transition Master Agreement.

(ii)

Gas Trading Day: The calendar day on which natural gas is traded corresponding to the applicable Gas Index. For example, in the absence of Holidays, a Gas Trading Day on a Monday reflects the day-ahead price applicable to gas flow on Tuesday. A Gas Trading Day on a Friday, in the absence of a Holiday, reflects the price for gas flow on Saturday, Sunday, and Monday.

(iii)

Required Natural Gas Quantity: The Required Natural Gas Quantity for each calendar day shall be expressed in MMBtu and equal to the sum of: [a]

the quantity of natural gas required for each Settlement Interval of the calendar day, calculated by multiplying: (1)

MWh of Qualifying Delivered Energy in such Settlement Interval by

(2)

the lesser of [i] the Heat Rate specified in Appendix 5.3 applicable to the product of the Scheduled Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour, or [ii] the Heat Rate

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specified in Appendix 5.3 applicable to the product of the Qualifying Delivered Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour; and [b]

any Start-Up Fuel required during the relevant calendar day; provided that in the event the duration of a Start-Up extends past one calendar day, then all of the Start-Up Fuel will be allocated to the calendar day associated with the first nonzero hourly schedule; and [c] any Transition Fuel required for all MSG Transitions in the relevant calendar day; provided that in the event the duration of an MSG Transition extends past one calendar day, then all of the Transition Fuel shall be allocated to the calendar day associated with the first non-zero hourly power schedule.

(iv)

Day Ahead Gas Quantity: The quantity of natural gas (expressed in MMBtu), if any, determined by SCE on each Gas Trading Day for an estimated dispatch on all calendar days associated with such Gas Trading Day. For example, in the absence of a Holiday, the Day-Ahead Gas Quantities for Saturday, Sunday, and Monday shall be calculated by SCE and provided to Seller on the immediately preceding Friday, and the Day-Ahead Gas Quantity for Tuesday shall be calculated by SCE and provided to Seller on the immediately preceding Monday.

(v)

Adjustment Gas Quantity: The Adjustment Gas Quantity for each calendar day shall equal the Required Natural Gas Quantity minus the Day-Ahead Gas Quantity corresponding to the applicable calendar day.

(vi)

Gas Commodity Cost: The Gas Commodity Cost shall equal the sum of the Day Ahead Gas Cost and Adjustment Gas Cost

(vii)

Day-Ahead Gas Cost: The Day-Ahead Gas Cost shall equal the Day-Ahead Gas Quantity multiplied by the applicable Gas Index for such Day-Ahead Gas Quantity.

(viii)

Adjustment Gas Cost: If the Adjustment Gas Quantity for a calendar day is:

(ix)

(a)

positive, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index published for and on the next Gas Trading Day immediately followingassociated with the applicable Operating Day plus $0.35/MMBtu; or

(b)

negative, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the lower of the Gas Index (i) used for the Day-Ahead Gas Cost, or (ii) published for the next Gas Trading Day immediately following the applicable Operating Day; unless the Generating Unit(s) had a Forced Outage, that renders the entire unit(s) unavailable, declared for any Settlement Interval. In such cases, the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index used for the Day-Ahead Gas Cost, from the first date of the occurrence of the Forced Outage up to and including the date when the next Generating Unit Start-Up is completed.

Transport Cost: Transport Cost shall mean the sum of the following two SoCalGas rate components (or any additional, replacement or successor components mutually agreed to in writing by the Parties) for transportation of natural gas to the Generating Unit’s SoCalGas Billing Meter expressed in $/MMBtu: (a)

the applicable rate set forth in the SoCalGas Transportation Contract, and

(b)

if applicable, Transported Gas Municipal Surcharge (G-MSUR), as set forth in SoCalGas Monthly Commercial/Industrial Rate Schedule Summary.

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Furthermore, Seller agrees that it is solely responsible for the “Surcharge to Fund the PUC Reimbursement Account” that is set forth in SoCalGas Rate Schedule No. G-SRF. Seller bears sole responsibility for obtaining an exemption from SoCalGas for the Rate Schedule No. G-SRF and Seller shall pay all or any portion of the surcharge for which it does not obtain the exemption. SCE retains no liability for the surcharge and Seller shall indemnify, defend, and hold SCE harmless against any costs or losses of SCE resulting from the surcharge set forth in Rate Schedule No. G-SRF. 3.2

Availability (a)

Capacity Payment Reduction. If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), (i) the Available Capacity of a Generating Unit is less than its Contract Capacity in any Settlement Interval in a month during the Delivery Period, or (ii) the Qualifying Delivered Energy from such Generating Unit is less than the Performance Tolerance Band Lower Limit in any Settlement Interval in a month during the Delivery Period, then the Capacity Payment Reduction for the affected Generating Unit for that month will be calculated as follows: (i)

For each Settlement Interval in the month, the “Price-Weighted Capacity Availability” is calculated as follows: Price-Weighted Capacity Availabilityi = (AMCPh(i) * Capacity Availabilityi) / AMCPavg(m) where: i = the Settlement Interval in month “m”

 MCP , if MCP  0  0, if MCP  0 AMCP =  h(i) = the Trading Hour corresponding to Settlement Interval “i” being calculated avg(m) = the simple average over all Settlement Intervals in month “m” For purposes of such calculation, Capacity Availability for any Settlement Interval shall not exceed the applicable Contract Capacity. (ii)

Using the Price-Weighted Capacity Availability calculated above, the “Price-Weighted Monthly Capacity Availability” for month “m” is calculated as follows: n

Price-Weighted Monthly Capacity Availabilitym = where:

 i

Price-Weighted Capacity Availabilityi

m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” (iii)

Using the Price-Weighted Monthly Capacity Availability calculated above, the “Capacity Price Adjustment Factor” for month “m” is calculated as follows: Capacity Price Adjustment Factorm = Price-Weighted Monthly Capacity Availabilitym / (Q * n)

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where: m = the relevant month within the Delivery Period being calculated Q = the Contract Capacity n = the number of Settlement Intervals in month “m” (iv)

Finally, using the Capacity Price Adjustment Factor calculated above, the “Capacity Payment Reduction” for month “m” is calculated as follows: [Use this formula for CCGTs or Boilers:] Capacity Payment Reductionm,CCGT / BOILER = 0.85 * Monthly Capacity Payment * (1 –Capacity Price Adjustment Factor) [Use this formula for CTs:] Capacity Payment Reductionm,CT = 0.50 * Monthly Capacity Payment * (1 – Capacity Price Adjustment Factor)

(b)

Ancillary Services Capacity Payment Reduction: If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), for each Ancillary Service listed in Section F of Appendix 1.4, the A/S Availability of a Generating Unit is less than the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4 in any Settlement Interval of a month, then the A/S Capacity Payment Reduction for the Generating Unit for that month will be calculated as follows: (i)

The “Monthly Available A/S Capacity” for month “m” is calculated as follows: n

Monthly Available A/S Capacitym = where:

 k

i

A/S Availabilityi,k

m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” k = the applicable Ancillary Service For purposes of such calculation, for each Ancillary Service, A/S Availability for any Settlement Interval shall not exceed the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4. (ii)

Using the Monthly Available A/S Capacity calculated above, the “A/S Price Adjustment Factor” for month “m” is calculated as follows: A/S Price Adjustment Factorm = Monthly Available A/S Capacitym /



A/S Maximum Capacityk * n) where: ( k

A/S Maximum Capacity is set forth in Section F of Appendix 1.4 m = the relevant month within the Delivery Period being calculated

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n = the number of Settlement Intervals in month “m” k = the applicable Ancillary Service (iii)

Using the A/S Price Adjustment Factor calculated above, the “A/S Capacity Payment Reduction” for month “m” is calculated as follows: [Use this formula for CCGTs or Boilers:] A/S Capacity Payment Reductionm,CCGT/ BOILER = 0.15 * Monthly Capacity Payment * (1 – A/S Price Adjustment Factor) [Use this formula for CTs:] A/S Capacity Payment Reductionm,CT = 0.50 * Monthly Capacity Payment * (1 – A/S Price Adjustment Factor)

(c)

3.3

Reduced Monthly Capacity Payment: The “Reduced Monthly Capacity Payment” shall be equal to (i) the Monthly Capacity Payment less (ii) the sum of [a] the Capacity Payment Reduction and [b] the A/S Capacity Payment Reduction.

Other Events Affecting Availability (a)

If Seller fails to take any action necessary to make the Product (or any portion of the Product) deliverable or otherwise available to SCE at the Energy Delivery Point, including maintenance, repair, or replacement of equipment in Seller’s possession or control that must be used for SCE to take delivery of the Product after, or transmit the Product from, the Energy Delivery Point, or such equipment fails for any reason including by reason of Force Majeure or any Outage, then, to the extent SCE is unable to take delivery of the Product after, or to transmit the Product from, the Energy Delivery Point by reason of such failures by Seller, the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(b)

If Seller fails to take any action within its control that is necessary to deliver the Natural Gas Requirements to the Generating Unit(s), including maintenance, repair or replacement of equipment in Seller’s possession or control that must be used to deliver the Natural Gas Requirements to the Generating Unit(s), or such equipment in Seller’s possession or control fails for any reason, including by reason of Force Majeure or any Outage, then, to the extent the Natural Gas Requirements are unable to be delivered to the Generating Unit(s), the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(c)

During the Delivery Period, the Generating Unit will be deemed to be unavailable for the quantity of Contract Capacity and A/S Maximum Capacity that is undeliverable by Seller during all Settlement Intervals that natural gas is unavailable due to loss, curtailment, interruption, or imposition of limitations of natural gas quantities not classified as firm under the SoCalGas Transportation Contract. For any Settlement Interval where the Generating Unit is unavailable under this Section 3.3(c), the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above. (d) If the SoCalGas Transportation Contract,) If the IFA, the PGA, or the MSA are not in effect at any time during the Delivery Period, the Generating UnitUnits shall be deemed to be unavailable for the Settlement Intervals during which such agreement or agreements are ineffective, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

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(ed) If Seller starts-up or operates any Generating Unit other than (i) pursuant to a Dispatch Notice or (ii) pursuant to a Non-SCE Dispatch, the Generating Unit shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above. ARTICLE 4 FUEL RESPONSIBILITIES 4.1

SCE’s Obligation

SCE shall provide the Day Ahead Gas Quantity to Seller by 6:3000 AM (PPT) on the Gas Trading Day applicable to each calendar day of the Delivery Period and be responsible for costs associated with providing the Required Natural Gas Quantity to the Generating Units solely through the Fuel Payment as set forth in ArticleSection 3.1(ed). SCE shall not be obligated to reimburse Seller for any separate charges assessed to Seller for gas transportation surcharges, fuel retention charges, imbalances, penalties, storage costs, or fuel-related taxes. 4.2

Seller’s Obligation

Seller shall be responsible for managing, nominating, scheduling, balancing, and transporting all of the Natural Gas Requirements needed to operate each Generating Unit. Seller shall also be responsible for all costs of natural gas associated with a Seller’s Initiated Test as set forth in Article 10. ARTICLE 5 COMBINED HEAT AND POWER (“CHP”) PROGRAM PROVISIONS 5.1

CHP Program Procurement and Seller Eligibility

Seller and SCE acknowledge and agree that SCE is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by SCE pursuant to this Confirmation is and shall be deemed to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to SCE that (a) the Generating Facility met the PURPA efficiency requirements (18 Code of Federal Regulations, Part 292, Section 292.205) as of September 2007; (b) as of the Confirmation Effective Date, the Power Rating of the Generating Facility equals [___] MW; and (c) as of the Confirmation Effective Date, the Generating Facility is a [Unit # 1 and Generating Unit # 3, together with the generating units that are subject to the obligations in the Transition PPA, constitute a Qualifying Facility][Exempt Wholesale Generating Facility]. Notwithstanding anything to the contrary set forth in this Agreement, Seller covenants that the Power Rating of the Generating Facility shall always exceed 5 MW.. 5.2

CPUC Approval; FERC Approval (a)

Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use commercially reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Either Party has the right to terminate this Confirmation on notice, which will be effective five Business Days after such notice is given, if CPUC Approval has not been obtained or waived by SCE in its sole discretion within 365 days after SCE files its request for CPUC Approval and a notice of termination is given on or before the 395th day after SCE files the request for CPUC Approval.(b) Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely

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issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report. (c) (c) Failure to obtain CPUC Approval in accordance with this Section 5.2(a) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of SCE to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval. (d)

5.3

Failure to obtain FERC Approval in accordance with this Section 5.2(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

Provision of Information

Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement. 5.4

Termination Right of Seller; Settlement Amount (i)

Seller has the right to terminate this Confirmation if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected by Buyer in a competitive solicitation. In such an instance, the termination of this Confirmation will be effective as of midnight the day before the commencement of any delivery period for any electric energy, capacity or attributes from the Generating Facility which is selected by Buyer in such competitive solicitation.

(ii)

Seller has the right to terminate this Confirmation upon providing to Buyer at least 180 days advance notice if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected in a competitive solicitation by a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 5.4(b) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

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(iii)

Seller has the right to terminate this Confirmation upon providing to Buyer at least 180 days advance notice if Seller (or any venture in which Seller is a participant) and the Generating Facility jointly enter into an agreement for the sale of electric energy, capacity or attributes with a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 5.4(c) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

(iv)

Notwithstanding anything to the contrary, no Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation under Section 5.4. ARTICLE 6 SCHEDULING COORDINATOR SERVICES

6.1

SCE as Scheduling Coordinator

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall take all actions and execute and deliver to SCE and the CAISO all documents necessary to authorize or designate SCE as Scheduling Coordinator (“SC”) for each of Generating Unit # 1 and Generating Unit # 3 with the CAISO effective as of the beginning of the Delivery Period. Seller shall not be entitled to any payment under this Confirmation until SCE is fully authorized as the SC for theeach such Generating Unit. During the Delivery Period, and after SCE is designated as SC for a Generating Unit, Seller shall not authorize or designate any other party to act as SC, nor shall Seller perform for its own benefit the duties of SC, and Seller shall not revoke SCE’s authorization to act as SC unless agreed to in writing by SCE. SCE shall submit bids and schedules to the CAISO in accordance with the Tariff and, subject to Article 9 below, the Operating Restrictions. Seller shall reasonably cooperate with SCE in performing any actions necessary prior to the start of the Delivery Period to allow each of Generating Unit # 1 and Generating Unit # 3 to be (i) dispatched (or otherwise scheduled to operate) for the first day of the Delivery Period and (ii) reported to or scheduled with the CAISO pursuant to the Tariff, either through SLIC or as otherwise required by the CAISO, as being in an outage at the commencement of the Delivery Period. All CAISO costs and revenues (including credits and other payments) associated with a dispatch of the Generating Unit # 1 or Generating Unit # 3 on the first day of the Delivery Period that are received by Seller or their SC on the day prior to the Delivery Period shall be for SCE’s account. 6.2

Notices

Subject to Seller complying with its obligations under this Confirmation, SCE, as SC, shall submit all notices and updates required under the Tariff regarding each Generating Unit’s status to the CAISO. Seller will comply with Article 9 of this Confirmation in providing such notices and updates. 6.3

CAISO Settlements

As SC, SCE shall be responsible for all settlement functions with the CAISO related to the Generating Units. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to the Generating Units, including any invoices or settlement data, in the format reasonably requested by SCE. 6.4

Terminating SCE’s Designation as SC

At least thirty (30) days prior to the expiration of the Delivery Period, the Parties will take all actions necessary to terminate the designation of SCE as SC as of 11:59 p.m. on the final date of the Delivery Period (“SC Replacement Date”). Such actions include the following: (a) Seller shall (i) submit to the CAISO a designation of a new SC to replace SCE effective as of the SC Replacement Date and (ii) cause its newly designated SC to submit

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a letter to the CAISO accepting the designation; and (b) SCE shall submit a letter to the CAISO resigning as SC effective as of the SC Replacement Date. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement SC. 6.5

Duties Related to Resource Adequacy Resources

If a Generating Unit is designated as a Resource Adequacy Resource, the following will apply: (a)

Seller shall take all actions necessary in order to allow SCE to reasonably perform its duties as an SC for a Resource Adequacy Resource, including, but not limited to, providing all information needed for SCE to include the Generating Units on SCE’s Supply Plan; and

(b)

SCE shall use the Resource Adequacy Availability Management (“RAAM”) software to allow Seller to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”), provided, (i) SCE is not required to use or change its utilization of SCE owned or controlled assets or market positions, to allow Seller to utilize the Substitution Rules, (ii) Seller, at its own expense, provides substitute capacity that complies with the Substitution Rules, (iii) Seller provides, as soon as practicable, but no later than 5:00 a.m. PPT the day bids are due in the IFM for the day Seller seeks to substitute capacity for, all information to SCE needed to substitute capacity pursuant to the Substitution Rules, including, but not limited to, the substitution start and end dates, the Resource ID for the substitute unit, a short description of the outage, the outage ID from SLIC application, and the amount of capacity to be substituted, (iv) SCE’s duties to take action under this subsection (b) are solely limited to inserting one (1) substitution request through RAAM per day; and (v) Seller causes, and is responsible for, the SC of the generating unit Seller seeks to substitute with to cooperate with SCE in making a substitute request and SCE is not responsible or liable for any costs, damages, penalties, charges, or liabilities (“Substitution Costs”) associated with such SC’s failure to cooperate or take the proper action; provided, further, if the CAISO develops a tool, application, or other means, for Seller to submit its own substitution request, then SCE shall not be required to take any action under this Section 6.5(b) to allow Seller to utilize the Substitution Rules. In no event shall SCE be responsible or liable for any Substitution Costs associated with Seller’s inability to utilize the Substitution Rules or rejection by the CAISO of any substitute capacity for any reason, including, but not limited to, any RAAM software limitations or failures, unless SCE is required to take action and such Substitution Costs or rejection result solely from SCE’s actions.

Seller shall provide the information set forth in Section 6.5(b)(iii) through the Outage Management System. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide such information through (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission of such information as soon as practicable. ARTICLE 7 RMR DESIGNATION 7.1

RMR Contract

IfUpon the request or designation by the CAISO designates the Generating Unit as an RMR unit at any time during the Delivery Periodthat any of the Generating Units be an RMR Unit, whether such request or designation is made directly by the CAISO or at the CAISO’s direction through the Scheduling Coordinator, Seller shall enter into an RMR Contract with CAISO under terms and conditions reasonably acceptable to SCE and Seller. Seller shall not otherwise pursue or enter into an RMR Contract without SCE’s consent. If theany Generating Unit is or becomes an RMR Unit during the Delivery Period, then for any dispatch by CAISO under the RMR Contract, the Operating Restrictions under this Confirmation will be subject to and superseded by any operating restrictions set forth in the RMR Contract or in the CAISO Master File for thethose Generating UnitUnits. Nothing in this Confirmation shall be construed to be a limitation on SCE’s right as a Transmission Owner under

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the Tariff to file with, or petition, to the FERC any objection or comments relating to any such RMR Contract or any actions SCE or CAISO intend to take with respect to any such RMR Contract. Seller represents, warrants, and covenants to SCE that if an RMR Contract for any Generating Unit for a period in which it is subject to the obligations in this Confirmation goes into effect at any time during the Term, no assignment of such RMR Contract to SCE will be required in connection with this Transaction. The Parties agree that neither this Confirmation nor this Transaction shall operate as an assignment of any such RMR Contract from Seller to SCE, and that in no event shall SCE be required to assume the obligations of Seller under any such RMR Contract. 7.2

RMR Settlements

If thea Generating Unit is designated as a CAISO RMR Unit, then no later than thirty (30) days after such designation by CAISO, Seller shall (i) authorize SCE to act as Seller’s representative (“RMR Settlement Coordinator”) to perform all RMR settlement functions for the RMR Units, (ii) authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder, and (iii) irrevocably assign to SCE all rights to receive any and all payments under the RMR Contract for the Delivery Period. Seller shall take all actions and execute and deliver to SCE all documents or contracts necessary, including any confidentiality agreements or other documents required under the RMR Contract, to authorize or designate SCE with the CAISO as its RMR Settlement Coordinator, and authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder. During the Delivery Period, Seller shall not authorize or designate any other party to act as RMR Settlement Coordinator, nor shall Seller perform for its own benefit the duties of RMR Settlement Coordinator, and Seller shall not revoke SCE’s authorization to act as RMR Settlement Coordinator unless agreed to by SCE. Upon SCE’s designation as the RMR Settlement Coordinator, SCE will be responsible for all RMR settlement functions in accordance with the Tariff and the RMR Contract, including rendering monthly RMR invoices to CAISO, settling any RMR charges incurred or RMR revenues earned, and resolving any RMR-related issues directly with CAISO. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to the Generating Unitseach of Generating Unit # 1 and Generating Unit # 3 (whether or not such Generating Units are subject to the obligations of this Confirmation at the time such correspondence or communication with the CAISO is received by Seller), including any invoices or settlement data, in the format reasonably requested by SCE. Upon receipt of any invoice from the CAISO for an RMR Unit (“RMR Invoice”), Seller shall promptly deliver such RMR Invoice to SCE. If the RMR Invoice amount is a charge from CAISO to Seller, Seller shall submit an invoice to SCE setting forth the amounts owed under the RMR Invoice, and SCE shall pay such amount to Seller for remission to CAISO within ten (10) Business Days after SCE’s receipt of such invoice. If the RMR Invoice amount is a payment from CAISO to Seller, Seller shall remit the amount of such payment to SCE within ten (10) Business Days after Seller’s receipt of such payment. To secure Seller’s obligations to remit to SCE any payments received under an RMR Contract or pursuant to an RMR Invoice, Seller hereby grants to SCE a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all revenues and accounts receivable of Seller with respect to the RMR Contract, and any and all proceeds resulting therefrom (collectively, “RMR Revenues”), whether now or hereafter held by, on behalf of, or for the benefit of, SCE, and Seller agrees to take such action as SCE reasonably requires in order to perfect SCE’s first-priority security interest in, and lien on (and right of setoff against) such RMR Revenues. SCE shall be the Secured Party with respect to the RMR Revenues and shall have all the rights and remedies of the Secured Party under the Transition EEI Agreement with respect to those RMR Revenues. 7.3

Disputes of RMR Invoices

The Parties agree that all RMR Invoices are subject to the Tariff and may be adjusted by the CAISO, or disputed by SCE, as RMR Settlement Coordinator, in accordance with the Tariff. The Parties agree that all RMR Invoices

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are subject to dispute between the Parties in accordance with Article Six of the Transition Master Agreement; provided, that the time limitation for adjustments or disputes of invoices set forth in Section 6.3 of the Transition Master Agreement shall not apply to RMR Invoices. Notwithstanding anything to the contrary contained in Articles Six or Ten of the Transition Master Agreement, the Parties agree that the obligations under this Article 7 with respect to the payment of RMR Invoices, or the adjustment of such RMR Invoices, shall survive the expiration or termination of the Agreementthis Confirmation for a period of one year beyond the time period which CAISO may adjust, modify or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the Tariff. 7.4

Terminating SCE’s Designation as RMR Settlement Coordinator

SCE’s designation as RMR Settlement Coordinator will remain in effect until the last applicable RMR Invoice and the data associated therewith is received by SCE and SCE completes all RMR settlement functions associated with such final RMR Invoice. In no event shall SCE be the RMR Settlement Coordinator for any operating day that is not within the Delivery Period. A new SC or RMR Settlement Coordinator shall not affect SCE’s ability to receive RMR settlement payment for any Generating Unit for any operating day during the Delivery Period when an RMR contract is in effect between Seller and the CAISO for such Generating Unit. ARTICLE 8 CAISO AND DELIVERY DEVIATION CHARGES 8.1

CAISO Costs and Revenues

Except as otherwise set forth in this Confirmation, SCE shall be responsible for CAISO costs and receive all CAISO revenues (including credits and other payments) incurred in connection with providing SC services, including costs and revenues associated with SCE and CAISO dispatches of theany Generating Unit. The procedures and calculation methodologies set forth in this Article 8 regarding CAISO costs and revenues are in respect to each Generating Unit. 8.2

CAISO Sanctions

If, during the Term, the CAISO implements or has implemented any sanction or penalty related to scheduling, outage reporting, or generator operation, and any such sanctions or penalties are imposed upon the Generating Unit(s) or to SCE as SC due solely to the actions or inactions of Seller, the cost of the sanctions or penalties shall be the Seller’s responsibility. 8.3

Scheduling and Delivery Deviation Charge

Seller shall pay SCE an SDD Charge if during any Settlement Interval the Qualifying Delivered Energy is less than the Performance Tolerance Band Lower Limit for such Settlement Interval. The SDD Charge is calculated as follows: If A < B, then SDD Charge = 0.5 * (B – A) * C where: A = Qualifying Delivered Energy for the Settlement Interval; B = Performance Tolerance Band Lower Limit; and C = SDD Price. Upon CAISO’s implementation of UDP, or any subsequent changes regarding the calculation of UDP, the Parties agree to negotiate in good faith to amend the SDD Charge calculation as necessary to maintain the economic

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balance of benefits and burdens contemplated under this Section 8.3. 8.4

SDD Administrative Charge

Seller shall pay SCE an SDD Administrative Charge if during any Settlement Interval Delivered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, for such Settlement Interval. The SDD Administrative Charge is calculated as follows: SDD Administrative Charge = Absolute Value (E – D) * F where: D = Delivered Energy for the Settlement Interval; E = Scheduled Energy for the Settlement Interval; and F = SDD Admin Price. 8.5

Allocation of Standard Capacity Product Payments and Charges

Seller agrees that, if the Generating Unit is a Resource Adequacy Resource, then it is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account. 8.6

Allocation of Charges Related to Generator Replace Tariff Provisions

If (a) a Generating Unit is designated as a Resource Adequacy Resource and (b) FERC approves or modifies the Tariff whereby, during periods that the Generating Unit is on a Planned Outage, the SC for a Resource Adequacy Resource is required to (i) replace the Generating Unit with a resource that is not a Resource Adequacy Resource or (ii) face the imposition of a charge, cost, sanction and/or penalty for failing to replace that Generating Unit, then Seller is responsible for (x) replacing the Generating Unit with a resource that is not a Resource Adequacy Resource, and (y) any and all charges, costs, sanctions and/or penalties for failing to replace all or a portion of the Generating Unit. Seller agrees that SCE is not required to take any action, or use or change its utilization of its owned or controlled assets or market positions, to allow Seller to replace the Generating Unit with a resource that is not a Resource Adequacy Resource; provided that SCE in its capacity as SC shall remain liable for compliance by it with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 9 AVAILABILITY NOTICES, BIDS, AWARDS AND DISPATCH 9.1

Notice of Availability

With respect to each Operating Day, no later than two (2) Business Days before each Trading Day, Seller shall provide to SCE using an SCE-provided web-based system (“Outage Management System”) an hourly schedule of the Available Capacity (for both Energy and Ancillary Services) that each Generating Unit is expected to have available for each hour of the applicable Operating Day (the “Availability Notice”). Seller must update SCE immediately using the Outage Management System if the Available Capacity of any Generating Unit changes or is likely to change after the Availability Notice has been submitted to SCE. Seller must follow up each such update through the Outage Management System with a telephonic update to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e). Seller shall accommodate SCE’s reasonable requests for

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changes in the time or form of delivery of the Availability Notices. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide Availability Notices using the form attached in Appendix 9.1 by (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission notice of such availability as soon as practicable. 9.2

9.3

Dispatch Notices and Operating Restrictions (a)

Dispatch Notices. SCE will have the right to dispatch each Generating Unit or Generating Units, seven (7) days per week and twenty-four (24) hours per day (including Holidays) and (i) at any level between PMin and Contract Capacity, inclusive, and (ii) at any level between Contract Capacity and PMax if instructed by the CAISO by providing Dispatch Notices to Seller electronically, subject to the terms and conditions set forth in this Confirmation. Subject to the Operating Restrictions, each Dispatch Notice will be effective unless and until SCE modifies such Dispatch Notice by providing Seller with an updated Dispatch Notice. If an electronic submittal is not possible for reasons beyond SCE’s control, SCE may provide Dispatch Notices by (in order of preference) electronic mail, facsimile transmission, or telephonically to the Seller personnel designated to receive such communications as listed in the Appendix 9.2(e). Day-Ahead Dispatch Notices, in the absence of an electronic submittal, shall be provided in a form substantially similar to Appendix 9.2(a). In addition to any other requirements set forth in this Confirmation, all Dispatch Notices will be made in accordance with the Tariff.

(b)

Start-Up Notices. If a Dispatch Notice includes a Start-Up, Seller shall notify SCE electronically when the respective Generating Unit has initiated a turbine start and again when that Generating Unit is synchronized and at Minimum Load ready to be dispatched to the applicable dispatch instruction. Seller shall provide an electronic or facsimile copy of a completed Start-Up Notice, in the form attached to this Confirmation in Appendix 9.2(b), to SCE within twenty-four (24) hours of the Start-Up. When a Dispatch Notice requires a Start-Up or shutdown, Seller will be responsible for coordinating all required switchyard switching with the respective grid control center, if applicable.

(c)

Operating Restrictions. The Operating Restrictions associated with the Product are specified in Appendix 1.4. In providing a Dispatch Notice, SCE shall use reasonable efforts to comply with the applicable Operating Restrictions. If SCE submits a Dispatch Notice that does not conform with the Operating Restrictions, then Seller shall immediately notify SCE of the non-conformity and SCE will modify its Dispatch Notice to conform to the applicable Operating Restrictions. Until such time as SCE submits a modified Dispatch Notice, Seller shall operate the applicable Generating Unit and deliver the Product in accordance with the Operating Restrictions.

(d)

Daily Operating Report. Seller shall provide SCE the Daily Operating Report, in the form attached in Appendix 9.2(d), the day immediately after each Operating Day, for all Generating Units.

(e)

Communication Protocols. The Parties shall agree to the communication protocols outlined in Appendix 9.2(e) to facilitate exchange of information between the Parties.

(f)

MSG Transition Notices. If a Dispatch Notice results in an MSG Transition, Seller shall notify SCE electronically of all such MSG Transitions and the configuration of the Generating Units under such MSG Transitions via the Outage Management System. If the Outage Management System is not available, Seller shall submit such notice via electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission notice of such availability as soon as practicable. Seller shall provide such notice within twenty-four (24) hours of last MSG Transition resulting from the respective Dispatch Notice.

CAISO Dispatch

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Any award or dispatch of a Generating Unit by the CAISO for any reason (whether pursuant to an RMR Contract, must offer obligations, Energy dispatches or otherwise), shall be deemed to be a dispatch by SCE for purposes of this Confirmation. The Energy dispatched shall be for SCE’s benefit hereunder, and SCE shall pay the costs of such CAISO awards and dispatches in accordance with the terms of this Confirmation as if such dispatches were directed by SCE. SCE shall be entitled to receive and retain for its own account any and all CAISO revenues for such awards and dispatches, including any availability payments under an RMR Contract for any Generating Unit. In no event shall a dispatch by the CAISO be considered a Non-SCE Dispatch pursuant to this Confirmation. CAISO dispatches following any Seller Initiated Test pursuant to Section 10.1 shall not obligate SCE for any associated costs incurred in starting any Generating Unit for, or operation during, such testing period. 9.4

Non-SCE Dispatch

During the Delivery Period, Seller shall not start-up or operate any Generating Unit other than (a) pursuant to a Dispatch Notice or (b) pursuant to a Non-SCE Dispatch. Seller shall, to the extent possible, notify SCE no later than 5:00 a.m. PPT at least two (2) Business Days in advance of the Trading Day of any start-up or operation pursuant to a Non-SCE Dispatch, and shall, except as otherwise required by Applicable Law, delay such start-up or operation if requested by SCE. Seller shall indemnify, defend, and hold SCE harmless against the costs or losses of SCE resulting from a Non-SCE Dispatch, including all (i) charges, sanctions, and penalties imposed by CAISO, and (ii) Seller’s Gas Costs incurred pursuant to any such start-up or operation. Imbalance Energy revenues net of any charges, sanctions, and penalties imposed by CAISO for a Non-SCE Dispatch shall be for Seller’s account. ARTICLE 10 TESTING 10.1

Testing

Seller may, at times and for durations reasonably agreed to by SCE, conduct necessary testing of the Generating Units. (a) Seller is permitted to conduct such testing during the hours in which Seller receives a Dispatch Notice (“SCE Dispatched Test”). Seller shall not be obligated to pay for the Fuel Payment relating to such SCE Dispatched Test, and SCE shall be responsible for all CAISO costs incurred and receive all revenues during such SCE Dispatched Test in accordance to Section 8.1 of this Confirmation. (b) Subject to Section 10.1(a), if Seller wishes to schedule and conduct a test (“Seller Initiated Test”), SCE shall not be obligated to pay the Fuel Payment to Seller, and Seller shall pay for all costs (including, but not limited to, start-up, fuel and/or transportation costs) relating to and arising out of such Seller Initiated Test in accordance with Section 9.4 of this Confirmation, and SCE shall pay to Seller, in the month following SCE’s receipt of such CAISO revenues, such revenues net of any resource specific charges, penalties, or sanctions associated with the Energy generated and delivered during such Seller Initiated Test. To the extent such Seller Initiated Test prevents SCE from dispatching theany Generating UnitsUnit as it would have absent such test, then, in accordance with the Section 3.2 of this Confirmation, the Generating UnitsUnit will be deemed unavailable. Seller must notify SCE of any Seller Initiated Test no later than 5:00 a.m. PPT at least three (3) Business Days in advance of the Trading Day of any start-up, operation or operational limitation(s) pursuant to the requested test. If Seller Initiated Test is agreed upon by SCE, SCE shall have the option to submit a SelfSchedule in the IFM for the agreed upon testing day for a duration the greater of (i) the number of hours required to complete the test, or (ii) the Minimum Run Time as referenced in Section B of Appendix 1.4. Notwithstanding anything to the contrary in this AgreementConfirmation, such Self-Schedule is not considered a Dispatch Notice.

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10.2

SCE Annual Test

At least once per calendar year at SCE’s request, SCE has the right to require Seller to demonstrate, pursuant to the protocols set forth in Appendix 10.2 (the “SCE Annual Test”), each Generating Unit’s ability to provide the Product in accordance with the terms of this Confirmation. In addition, as part of the SCE Annual Test, SCE may inspect the Generating Facility to confirm the configurations of the Generating Unit(s) provided for in Appendix 1.4. The SCE Annual Test shall be at a time mutually agreed to by the Parties. If, during an SCE Annual Test, a Generating Unit fails to demonstrate its ability to provide the Product or any portion thereof (a “Failed Test”), Seller shall, at Seller’s cost and expense, promptly make all necessary repairs to such Generating Unit, and any portion thereof, and/or take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation. The results of any Failed Test will be used to determine the Available Capacity for the applicable Generating Unit, and accordingly, Reduced Monthly Capacity Payments shall apply for such Generating Unit until Seller demonstrates, in accordance with Appendix 10.2, a successful test. Seller agrees that any subsequent test that is performedrequired to demonstrate that Seller has remediedcompliance for a Failed Test shall be a Seller Initiated Test. ARTICLE 11 OUTAGES 11.1

Planned Outages

Upon the later of the Confirmation Effective Date or twenty-four (24) months prior to the beginning ofNo later than 60 days prior to the Delivery Period, and no later than January 1, April 1, July 1, and October 1 of each calendar year thereafter throughout the Term, Seller shall submit to SCE the portion of the Seller’s schedule of proposed Planned Outages (“Outage Schedule”) for the following twenty-four (24) month period that overlaps the Delivery Period via the Outage Management System. If the Outage Management System is not available, Seller shall submit the Outage Schedule in substantially the form set forth in Appendix 11.1. Within twenty (20) Business Days after its receipt of an Outage Schedule, SCE shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Accepted Electrical Practices, accommodate SCE’s requests regarding the timing of any Planned Outage. Seller shall cooperate with SCE to arrange and coordinate all Outage Schedules with the CAISO in compliance with all CAISO Outage scheduling and reporting requirements. Seller will communicate to SCE all changes to a Planned Outage including estimated time of return of each Generating Unit as soon as practicable after the condition causing the change becomes known to Seller. 11.2

11.3

Restrictions to Planned Outages (a)

No Planned Outages shall be scheduled or planned from each May 1 through September 30 during the Delivery Period for any Generating Unit subject to this Confirmation, without prior written consent from SCE.

(b)

In the event that the Seller has a Planned Outage for any Generating Unit subject to this Confirmation that becomes coincident with a CAISO-declared system emergency, Seller shall make all reasonable efforts to reschedule such Planned Outage.

Notice of Forced Outages

Seller shall communicate Forced Outages by telephoning SCE’s Generation Operations Center within ten (10) minutes of the commencement of the Forced Outage, at the telephone numbers listed in Appendix 9.2(e). Seller shall utilize SCE’s Outage Management System to enter Outage information as required by the Tariff within twenty (20) minutes of the Forced Outage. If the CAISO imposes a sanction or penalty upon SCE as SC due to Seller’s failure to timely provide SCE with a report of a Forced Outage or Planned Outage for any Generating Unit subject to this Confirmation, Seller shall be responsible for such sanction or penalty.

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11.4

Reports of Forced Outages or Planned Outages

Seller shall promptly prepare and provide to SCE, using the Outage Management System or forms, all reports of Forced Outages or Planned Outages for any Generating Unit subject to this Confirmation that SCE may reasonably require for the purpose of enabling SCE to comply with CAISO requirements or any Applicable Laws. Seller shall provide to SCE notice of a Planned Outage no later than seventy-two (72) hours prior to the beginning of any Planned Outage. Seller shall also report all Forced Outages and Planned Outages in the Daily Operating Report. 11.5

Inspection

In the event of a Forced Outage, SCE shall have the right to inspect any Generating Unit and all records relating thereto on any Business Day and at a reasonable time, and Seller shall reasonably cooperate with SCE during any such inspection. ARTICLE 12 METERING, COMMUNICATIONS, AND TELEMETRY 12.1

SCE Access

All communication, metering, telemetry, and associated generation operation equipment will be centralized into each Generating Unit’s Distributed Control System (“DCS”) or Supervisory Control And Data Acquisition system (“SCADA”). Seller shall configure each Generating Unit’s DCS/SCADA so that SCE may access it via the Generation Management System (“GMS”) from SCE’s Generation Operations Center (“GOC”). Seller shall ensure that the access link will provide a monitoring and control interface to enable automatic dispatch of each Generating Unit. Seller shall link the systems via an approved SCE communication network, utilizing existing industry standard network protocol, as approved by SCE. The connection will be bidirectional in nature and used by the Parties to exchange all data points to and from the GOC. SCE and Seller shall each have shared access to information concerning gas data (including data regarding nominations, confirmations, allocations, imbalances, and usage) through electronic bulletin boards or remote meter reading devices with respect to all Natural Gas Requirements for each Generating Unit. Seller shall be responsible for the costs of installing, configuring, maintaining and operating the DCS/SCADA and internal site links for each Generating Unit. 12.2

Control Logic

Seller will ensure that each Generating Unit’s DCS/SCADA control logic will be configured to control the Generating Unit in multiple plant configurations as applicable. Each Generating Unit’s control logic will incorporate control signals from multiple locations to perform Energy dispatch, Ancillary Services, and supplemental energy functions. Control logic will perform all coordinated megawatt control and Automatic Generation Control (“AGC”) independently for each Generating Unit. 12.3

Delivery of Data

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall provide SCE with all facility and metering information necessary to communicate with SCE, including the information set forth in Appendix 12.3. 12.4

Satellite Communication System

Seller is responsible for installing, testing, commissioning, and maintaining the Satellite Communications System (“SCS”) for each Generating Unit in accordance with instructions provided by SCE and the SCS vendor. Seller shall grant SCE reasonable access to the Generating Units during regular business hours for routine calibration and maintenance of the SCS at any time prior to the expiration of the Delivery Period. SCE may, at any time, halt the installation, testing, commissioning, or maintenance of the SCS. SCE shall be responsible for the costs associated with installation, testing, commissioning, and maintenance of the SCS, and will provide the SCS to

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Seller for installation. ARTICLE 13 OPERATION, MAINTENANCE, AND REPAIR 13.1

Seller’s Operation Obligations During the Delivery Period:

13.2

(a)

Seller shall operate each Generating Unit in accordance with Accepted Electrical Practices, Applicable Laws, the applicable Permit Requirements, applicable California utility industry standards, including the standards established by the California Electricity Generation Facilities Standards Committee pursuant to Public Utilities Code Section 761.3 and enforced by the CPUC, CPUC General Order 167, and CAISO mandated standards, as set forth in the Tariff (collectively, “Industry Standards”);

(b)

Seller shall maintain a daily operations log for each Generating Unit which shall include information on power production, fuel consumption and efficiency (if applicable), availability, maintenance performed, Outages, changes in operating status, inspections and any other significant events related to the operation of each Generating Unit. In addition, Seller shall maintain all records applicable to each Generating Unit, including the electrical characteristics of the generators and settings or adjustments of the generator control equipment and protective devices. Information maintained pursuant to this Section 13.1 shall be provided to SCE, within five (5) Business Days of SCE's request; and

(c)

Seller shall maintain and make available to SCE and the CPUC, or any division thereof, records, including the plant operations logbooks demonstrating that the Generating Units are operated and maintained in accordance with Industry Standards. Seller shall comply with all reporting requirements and permit on-site audits, investigations, tests, and inspections permitted or required under any Applicable Laws, Permit Requirements, or Industry Standards.

Seller’s Maintenance and Repair Obligations During the Delivery Period: (a)

Seller shall inspect, maintain, and repair each Generating Unit, and any portion thereof, in accordance with applicable Industry Standards and Accepted Electrical Practices. Seller shall maintain and deliver to SCE within five (5) Business Days of aupon request, all maintenance and repair records and plant equipment test data of each Generating Unit; provided, however, if Seller must obtain such records and data from a third-party, Seller shall promptly request such records and data from the applicable third-party and shall provide the requested records and data to SCE within five (5) Business Days of receipt.

(b)

In the event that: (i)

an SCE Annual Test demonstrates that the Available Capacity of a Generating Unit is less than or equal to seventy-five percent (75%) of Contract Capacity, or

(ii)

an equipment failure with respect to a Generating Unit results in the Available Capacity of such unit being less than or equal to seventy-five percent (75%) of Contract Capacity on average for a period of time exceeding seven (7) days,

Seller shall repair such Generating Unit in accordance with Accepted Electrical Practices and the procedure set forth in this Article 13. Within fourteen (14) days of any such failure, Seller shall complete a Successful Repair or present to SCE a written report providing a description of the

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reason for the failure and a plan and schedule for completing a Successful Repair within the time specified in the repair plan (“Repair Plan”). If SCE and Seller disagree about the Repair Plan, SCE may, at its expense, hire an independent third party engineering firm reasonably acceptable to Seller (“IE”), to assess the situation and make recommendations for completing a Successful Repair. Upon SCE providing two (2) Business Days notice by SCE., Seller shall grant the IE and SCE personnel access to the Generating Facility and all relevant operational log books, maintenance records and reports. Seller shall use best efforts to follow the recommendations of the IE’s engineering report for achieving a Successful Repair. Until a Successful Repair is demonstrated, the Generating Unit(s) will be deemed unavailable for purposes of Section 3.2 of this Confirmation; provided, upon Seller’s demonstration of a Successful Repair, the Generating Unit(s) will be deemed available retroactive to the hour that such Successful Repair was initiated;

13.3

(c)

Subject to Section 13.2(b), Seller shall promptly make all necessary repairs to each Generating Unit, and any portion thereof, and take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation; and

(d)

Seller shall not allow the Available Capacity of any Generating Unit to fall below seventy-five percent (75%) of Contract Capacity on average for a period of: (i)

six (6) months (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) due to Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such six (6) month period (or longer cure period identified in the IE’s written report); or

(ii)

sixty (60) days (whether or not consecutive) within a rolling twelve (12) month period (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) for any reason or circumstance, including Forced Outage, but excluding Planned Outage and Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such sixty (60) day period (or longer cure period identified in the IE’s written report).

Operational Representations, Warranties, and Covenants by Seller

Seller represents, warrants, and covenants with respect to Sections 13.3(a) through (d) and Seller covenants with respect to Section 13.3(e) to SCE that: (a)

Prior to the start of the Delivery Period, Seller has executed a PGA and MSA; Seller has delivered to SCE a true and complete copy of such PGA and MSA; and such PGA and MSA, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the duration of the Delivery Period; provided that Seller shall be allowed to agree to any amendment or modification to the PGA and/or MSA if FERC approves a new form of such agreements for the CAISO, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10) Business Days of such amendment or modification.

(b)

Prior to the start of the Delivery Period, Seller has executed all necessary grid connection, maintenance, or transmission facility services agreements; Seller has delivered to SCE a true and complete copy of such agreements; and such agreements, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the Term; provided that if FERC authorizes the Transmission Owner to amend or modify such agreements with Seller, Seller is authorized to accept any such FERC-approved modified or amendment agreement, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10)

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Business Days of such amendment or modification. (c)

Prior to the start of the Delivery Period, Seller has good and defensible title, or valid and effective leasehold rights in the case of leased property, to each Generating Unit subject to this Confirmation , free and clear of all liens, charges, claims, pledges, security interests, equities, and encumbrances of any nature whatsoever other than (i) the lien of current taxes not delinquent; (ii) liens, charges, claims, pledges, security interests, equities, and encumbrances that in the aggregate are not substantial in amount and do not detract from or interfere with the ability of Seller to deliver the Product; or (iii) liens listed in Appendix 13.3(c) delivered by Seller to SCE prior to the Confirmation Effective Date (the “Disclosure Schedule”);

(bd) On the Confirmation Effective Date, the “Historical Outage Report” sets forth true and accurate historical data of (a) the dates during which each Generating Unit (including the Generating Units that will become subject to the obligations of this Confirmation during the Delivery Period) was available to generate Energy during the period from the beginning of the calendar year two (2) years prior to the Confirmation Effective Date2009 to the present regardless of whether or not such Generating Unit did in fact generate Energy, and each Generating Unit's capacity to generate Energy for each of those dates during which the Generating Unit was available, and (b) for those dates when each Generating Unit was not available to generate Energy, the reasons for such unavailability; and (c)

Noe) In the event SCE is not the SC, no later than two weeks prior to the first day of the Delivery Period, Seller shall take all actions necessary with the CAISO and SCE to ensure that by the day immediately prior to the first day of the Delivery Period, the CAISO Master File and, if applicable, the RMR Contract reflect the values that SCE deems appropriate based on the Operating Restrictions under this Confirmation. If, at any time prior to the termination of this Confirmation, any action or inaction of Seller, or a condition of any Generating Unit that could result in a revision to the CAISO Master File or to the operating restrictions set forth in an RMR Contract, then Seller shall promptly give notice to SCE and shall use all reasonable efforts to maintain the Operating Restrictions exactly as they existed on the Confirmation Effective Date. ARTICLE 14 ELECTRIC SYSTEM RELIABILITY STANDARDS

During the Delivery Period, Seller shall be (i) responsible for complying with any NERC Reliability Standards applicable to the Generating Units, including registration with NERC as the Generator Operator for the Generating Units or other applicable category under the NERC Reliability Standards and implementation of all applicable processes and procedures required by NERC, WECC or CAISO for compliance with the NERC Reliability Standards; and (ii) liable for all penalties assessed by NERC (through WECC or otherwise) for violations of the NERC Reliability Standards by the Generating Facility or Seller, as Generator Operator or other applicable category. However, if Seller learns that NERC (through WECC or otherwise) is considering or intends to assess Seller with a penalty that Seller believes is attributable to SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the potential assessment, Seller shall provide SCE with sufficient notice to allow SCE to take part in administrative processes, discussions or settlement negotiations with NERC, WECC or other entity arising from or related to the alleged violation or possible penalty. If the penalty is nonetheless assessed in spite of SCE’s participation in the processes, discussions or settlement negotiations, or SCE waives its right to take part in the processes, discussion or settlement negotiations, SCE shall reimburse Seller for the penalty to the extent that (a) it was solely caused by SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the violation; and (b) Seller can establish to SCE’s reasonable satisfaction that the penalty was actually assessed against Seller by NERC and paid by Seller to NERC. If SCE took part in and agreed to the terms of settlement, SCE shall also reimburse Seller for any payment made by Seller in settlement of a claim of violation by or on behalf of NERC, to

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the extent that (x) the claim being settled was solely caused by SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the claim; and (y) Seller can establish to SCE’s reasonable satisfaction that Seller actually made the payment to NERC under the settlement. ARTICLE 15 CREDIT TERMS AND MARK-TO-MARKET VALUE 15.1

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEI Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, if: (i) Seller has’s Exposure to SCE in respect of the Transaction, then the amount of Exposure for this Transaction is deemed to be zero dollars ($0for this Transaction shall be zero dollars ($0) and (ii) SCE’s Exposure to Seller plus the Independent Amount, if any, for this Transaction shall not exceed three million two hundred thousand dollars ($3,200,000) (unless otherwise defined, capitalized terms in this Article 15 are used with the meanings ascribed to them in the Transition Collateral Annex). 15.2

Independent Amount

If Seller’s Credit Rating is lower than BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch, Seller shall have a Full Floating Independent Amount of the amount equal to ten percent (10%) of the market value of this Transaction. Upon the Confirmation Effective Date and until the start of the Delivery Period the term “market value” shall mean the sum of the Monthly Capacity Payments to be paid under this Transaction for the Delivery Period, and upon the start of the Delivery Period the term “market value” shall mean the sum of the Monthly Capacity Payments for the current month and all remaining months of the Delivery Period to be paid under this Transaction. 15.3

Mark-to-Market Value

For purposes of determining Exposure for this Transaction, the Parties shall calculate the Current Mark-to-Market Value of this Transaction using the following methodology (unless otherwise defined, capitalized terms in this Section 15.2 are used with the meanings ascribed to them in the Collateral Annex). On any Calculation Date, the Current Mark-to-Market Value for this Transaction will be calculated by taking the sum of the Present Values for each remaining (full or partial) month prior to the termination of this Transaction using the equation below: Current

Mark-to-Market

Value

=

where:

and:

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Variable n i

Pt,i

Po,i

Gt,i

Go,i

HRi

Qi c d

Description The number of forward months included in the mark-to-market calculation. A forward month. For the balance of the month of the Calculation Date, i=0. For the month following the month of the Calculation Date, i=1, etc. The midpoint from aweighted average of Forward Price AssessmentAssessments for SPNP15 on-peak and off peak power for the relevant forward month i on the Calculation Date for combined cycle technology (for combustion turbine technology, the on-peak price will be multiplied by 1.20 for the relevant forward month i). If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price shall be usedcalculated from the Forward Price Assessments for NP15 on-peak and off-peak power for the last available year. The midpoint from aweighted average of Forward Price AssessmentAssessments for SPNP15 on-peak and off-peak power for the relevant forward month i on the Confirmation Effective Date for combined cycle technology (for combustion turbine technology, the on-peak price will be multiplied by 1.20 for the relevant forward month i). . If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price shall be usedcalculated from the Forward Price Assessments for NP15 on-peak and off-peak power for the last available year. NYMEX Southern California GasPG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCalPG&E City Gate Basis) for the relevant forward month i on the Calculation Date. If no such gas price is available on the Calculation Date, then a proxy value of NYMEX Southern California Border natural gas plus rate G-BTS1 located in SoCalGas Schedule No. G-BTS (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCal Border Basis plus rate G-BTS1 per MMBtu) for the relevant forward month i shall apply. If neither of the aforementioned gas prices isare available, then the gas price for the relevant calendar month of the last available year shall be used. NYMEX Southern California GasPG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCalPG&E City Gate Basis) for the relevant forward month i on the Confirmation Effective Date. If no such gas price is available on the Confirmation Effective Date, then a proxy value of NYMEX Southern California Border natural gas plus rate G-BTS1 located in SoCalGas Schedule No. G-BTS (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCal Border Basis plus rate G-BTS1 per MMBtu) for the relevant forward month i shall apply. If neither of the aforementioned gas prices isare available, then the gas price for the relevant calendar month of the last available year shall be used. The Heat Rate associated with the Contract Capacity as specified in Appendix 5.3 of this Confirmation. The Contract Capacity multiplied by the hours remaining under the Transaction for the relevant forward month Interest rate (annualized) Number of compounds per year (e.g. c = 12 if

Units

$/MWh

$/MWh

$/MMBtu

$/MMBtu

MMBtu/MWh MW * Hours %

= monthly)

Number of days between calculation date ( ) and payment date.

A positive Current Mark to Market Value implies SCE has the potential for realization of market gains and thus has Exposure to Seller’s default or non-performance. Notwithstanding anything to the contrary contained in the Transition Collateral Annex or this Confirmation, the Parties shall determine the Settlement Amount for this Transaction in accordance with Section 5.2 of the Master Agreement.

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ARTICLE 16 ASSIGNMENT In the event of an Assignment permitted under Section 10.5 of the Transition Master Agreement, (i) any such assignee shall agree in writing to be bound by the terms and conditions hereof, (ii) the Collateral Threshold for such assignee shall automatically be deemed to be zero unless the non-assigning Party otherwise agrees, and (iii) the transferring Party must deliver such tax and enforceability assurance as the non-assigning Party may reasonably request. Any assignment in violation of this Article 16 shall be null and void.

ARTICLE 17 CONFIDENTIALITY In addition to the Parties’ obligations under Section 10.11 of the Transition Master Agreement, with respect to this Transaction, Seller agrees that any data, information, or other material Seller receives from SCE or the CAISO pursuant to or in connection with this Confirmation, including any schedules, bids, awards, dispatches, Dispatch Notices, updated Dispatch Notices, settlement statements, Ancillary Services dispatches or awards, or any other information related to the Product (collectively, "Dispatch Data"), shall be confidential to SCE, and Seller shall use such Dispatch Data or other confidential information or material solely in connection with its performance of its obligations under this Confirmation and for no other purpose. Furthermore, Seller shall not disclose this Dispatch Data or other confidential information to any of its employees, personnel, contractors, agents, or consultants who are engaged wholly or in part in the business of marketing or selling wholesale electrical power or natural gas unless such employees, personnel, contractors, agents, or consultants (a) are directly engaged in performing Seller's obligations under this Confirmation, (b) need to know such information in order to perform Seller's obligations under this Confirmation, (c) are informed of (i) the confidentiality of such Dispatch Data and any information governed by this Article 17 and Section 10.11 of the Transition Master Agreement and (ii) the requirements of this Confirmation and the Transition Master Agreement, and (d) are directed to comply with the requirements of this Confirmation and the Transition Master Agreement. Seller agrees that irreparable damage to SCE would occur if Seller were to breach its obligations under this Article 17 and that SCE shall be entitled to all available remedies at law or in equity. ARTICLE 18 PAYMENT, NETTING AND SETOFF Unless otherwise set forth herein, the Parties agree that Sections 5.3, 5.6, and Article Six of the Transition Master Agreement shall apply to this Transaction and that any payment due to or due from either Party to the other Party pursuant to the terms of this Confirmation shall be subject to such provisions. ARTICLE 19 CALIFORNIA AIR RESOURCES BOARD REPORTING REQUIREMENTS During the Term, Seller shall provide such information as SCE deems necessary for SCE to comply with those GHG emissions reporting requirements adopted by the California Air Resources Board (“CARB”), or as Seller is otherwise required to provide by Applicable Law or Governmental Authority. ARTICLE 20 ENVIRONMENTAL CHARGES

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20.1

Indemnification

Seller is solely responsible for all Environmental Costs and, other than as provided in Sections 20.2 through 20.4, all GHG Charges, Seller’s Compliance Obligation, and all other costs associated with the implementation and regulation of Greenhouse Gas emissions (whether in accordance with AB 32 or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions implemented and regulated by an authorized Governmental Authority) with respect to the Generating Unit(s) and/or Seller. Seller shall indemnify, defend and hold SCE harmless from and against all liabilities, damages, claims, losses, costs and/or expenses (including, without limitation, attorneys’ fees) incurred by or brought against SCE in connection with such Environmental Costs, GHG Charges, Compliance Obligation, and such other costs. 20.2

Greenhouse Gas Emissions Compliance Cost

Notwithstanding anything to the contrary in Section 20.1, and subject to Seller’s compliance with Section 20.3, in the event that a Governmental Authority imposes any taxes, charges, or fees on the Generating Unit(s) or Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (collectively, “GHG Charges”), Seller shall provide SCE documentation of such GHG Charges within 90 days of Seller incurring the obligation to pay the GHG Charge and such documentation shall establish to SCE’s reasonable satisfaction (all such documentation identified in subsections (a)-(f) below shall be collectively referred to hereinafter as “GHG Documentation”), that: (a)

Seller is actually liable for the GHG Charges during the Delivery Period;

(b)

the Applicable Law imposing the GHG Charge was (i) not in effect or (ii) not scheduled to become effective and applicable to the Generating Unit(s) as of the Confirmation Effective Date;

(c)

the specific amount of the GHG Charges;

(d)

the GHG Charge was imposed upon Seller by an authorized Governmental Authority in whose jurisdiction the Generating Units are located, or which otherwise has jurisdiction over Seller or the Generating Units;

(e)

Seller has paid the Governmental Authority identified in (d) above the full amount of the GHG Charge for which Seller seeks reimbursement from SCE under this Section 20.2; and

(f)

Seller took all reasonable steps to mitigate the cost or amount of such GHG Charges, including utilizing any GHG Credits or revenues described in Section 20.3(a)(i) below; provided, that the reasonable steps shall not be deemed to require Seller to make capital improvements to the Generating Unit.

SCE shall reimburse Seller for such GHG Charge within forty-five (45) calendar days of SCE’s receipt of the GHG Documentation. In no event shall SCE be responsible for GHG Charges associated with Greenhouse Gas emissions that exceed the GHG Cap or a Non-SCE Dispatch during the Term. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period. 20.3

Greenhouse Gas Emissions Credits

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(a)

In the event that, during the Term, Seller is: (i)

allocated or issued, or has the right to obtain, at no cost to Seller other than administrative or overhead costs, allowances, credits, or other similar rights to emit Greenhouse Gas in accordance with a cap-and-trade or any other federal, state or local legislation, other than AB 32, implemented by an authorized Governmental Authority (“GHG Credits”) to offset or reduce any Greenhouse Gas emissions, then Seller shall obtain and utilize such allowances or credits to mitigate any GHG Charge at no cost to Buyer;

(ii)

allocated or issued or has the right to obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for a portion of or its entire fleet of generating units (all or some of the generating units owned, managed, or controlled by Seller that are subject to any Greenhouse Gas legislation, regulation, law or other similar governmental action) (“Seller’s Fleet”), then Seller shall utilize a proportional amount of such allowances or credits to mitigate any GHG Charge at no cost to SCE; or

(iii)

allocated or receives revenues, whether specific to the Generating Unit(s) or Seller’s Fleet, associated with any allowance or credit allocated at no cost to Seller other than administrative or overhead costs and associated with Greenhouse Gas emissions, then Seller shall remit any such revenue or, if allocated to Seller’s Fleet, the proportional amount of such revenue, to SCE to mitigate any GHG Charge.

For purposes of Section 20.3(a)(ii) and (a)(iii) above, the proportional amount of allowances, credits, or revenues, as applicable, shall be calculated based on the method, formula or other similar calculation by which the Governmental Authority used to determine the amount of GHG Credits (“GHG Calculation”) attributable to each Generating Unit compared to the sum of all GHG Calculations for all generating units within Seller’s Fleet. (b)

In the event (i) Seller is not allocated, issued, or granted the right to otherwise obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for the Generating Units pursuant to Section 20.3(a) above; (ii) Seller is not allocated or issued sufficient GHG Credits to offset GHG Charges attributable to the Generating Units; or (iii) a liquid market for GHG Credits develops and is available to purchase GHG Credits to offset the GHG Charges, then SCE may, at its option, either: (1) self-supply GHG Credits for the Generating Unit(s); or (2) provide Notice to Seller directing Seller to purchase GHG Credits sufficient to cover the GHG Charges associated with the Generating Unit(s). If SCE elects to direct Seller to purchase GHG Credits, Seller shall purchase the number of GHG Credits set forth in the Notice and SCE shall reimburse Seller for those GHG Credits at the lower of Seller’s cost or the prevailing market price at the time the GHG Credits were obtained. In no event shall either Party purchase GHG Credits from an Affiliate.

(c)

All GHG Credits (i) allocated, issued or granted, at no cost to Seller other than administrative or overhead costs, rights to Seller for the Generating Units or (ii) paid for or utilized by SCE shall be the sole and exclusive property of SCE; and any excess GHG Credits (GHG Credits not utilized by SCE under this Confirmation) or revenues resulting from GHG Credits shall be the sole and exclusive property of SCE and shall be retained by SCE.

For purposes of this Section 20.3, all references to “Seller” shall be deemed to include Seller’s parent company, holding company or other entity to which allowances or credits may be or have been allocated to or given rights to obtain, at no cost to such entity other than administrative or overhead costs, for the Generating Units. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or

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reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period.

20.4

Compensation for Seller’s Compliance Obligation (a)

(b)

If Seller is not eligible for an exemption and subject to Section 20.5, Buyer shall satisfy its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period, in arrears of the creation of such Compliance Obligation, by: (i)

Providing to Seller the Allowances and/or the Offset Credits that will permit Seller to satisfy the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, as further described in Section 20.4(b);

(ii)

Paying to Seller the GHG Compliance Costs for the Delivery Period, as further described in Section 20.4(c); or

(iii)

Utilizing any combination of the compensation methods described in Sections 20.4(b) and 20.4(c), such that Buyer shall fulfill its obligation to compensate Seller for the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period by providing Allowances, Offset Credits and/or the GHG Compliance Costs.

If Buyer, in its sole discretion, elects to provide Seller with Allowances and/or Offset Credits, then Buyer shall, at any time (or from time to time) after Buyer has received the data for calculating the Required Natural Gas Quantity that allows Buyer to calculate Seller’s compensation for any portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, and pursuant to one or more conveyances of Allowances and/or Offset Credits, convey and deliver to Seller, either electronically or otherwise, such Allowances and/or Offset Credits; provided that: (i)

Buyer must transfer such Allowances and/or Offset Credits in a timely manner so as to permit Seller to satisfy the Compliance Obligation imposed on Seller during the Delivery Period (including, without limitation, Seller’s annual compliance obligation, as described in Section 95855 of the GHG Regulations);

(ii)

Upon each conveyance and delivery of such Allowances and/or Offset Credits by Buyer to Seller, Seller shall take all actions to accept delivery of such Allowances and/or Offset Credits such that the conveyed Allowances and/or Offset Credits shall have transferred from Buyer’s account to Seller’s account in accordance with the GHG Regulations;

(iii)

Buyer may, in its sole discretion, reduce the number of Allowances it delivers to Seller pursuant to this Section 20.4(b) by some or all of the Free Allowances that are deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s) and to the extent not applied to a prior conveyance and delivery of Allowances by Buyer to Seller under this Confirmation;

(iv)

The amount of Offset Credits that Buyer conveys and delivers to Seller throughout the Delivery Period (if any) will not exceed the Quantitative Usage Limit for the total Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period; and

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(v)

(c)

No later than three (3) Business Days before Buyer conveys and delivers such Allowances and/or Offset Credits to Seller, and also on each of Transfer Date 1, Transfer Date 2 and Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period), Buyer shall deliver a notice to Seller (the “Transfer Notice”), which Transfer Notice shall inform Seller of: (1)

The number of Allowances and/or Offset Credits that Buyer has conveyed and delivered to Seller pursuant to any previous Transfer Notices, and the time-period during the Delivery Period for which such Allowances and/or Offset Credits applied;

(2)

The number of Allowances and/or Offset Credits that Buyer shall convey and deliver to Seller pursuant to the subject Transfer Notice, and the time-period during the Delivery Period for which such Allowances and/or Offset Credits shall apply;

(3)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Transfer Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(4)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Transfer Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(5)

The date on which Buyer shall convey and deliver such Allowances and/or Offset Credits pursuant to the subject Transfer Notice;

(6)

The number of Free Allowances deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s), which Buyer shall deduct from Buyer’s compensation of Seller to the extent such Free Allowances have not been applied to a prior conveyance and delivery of Allowances by Buyer to Seller pursuant to a Transfer Notice under this Confirmation; and

(7)

The information set forth in Section 20.4(c)(i) through (vi), if Buyer has determined to compensate Seller in part by paying to Seller the GHG Compliance Costs in accordance with Section 20.4(c).

If Buyer, in its sole discretion, elects to compensate Seller by paying to Seller the GHG Compliance Costs, then Buyer (x) shall deliver a notice to Seller on or before Transfer Date 1, Transfer Date 2 and/or Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period) (such notice, the “Required Payment Notice”), and (y) may, in its sole discretion, deliver a notice to Seller on or before any Optional Transfer Date (such notice, the “Optional Payment Notice”), which Required Payment Notice and Optional Payment Notice shall inform Seller of: (i)

Buyer’s intent to pay to Seller such GHG Compliances Costs;

(ii)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Required Payment Notices and Optional Payment Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(iii)

The time-period during the Delivery Period for which Buyer has compensated Seller pursuant to any previous Required Payment Notices or Optional Payment Notices;

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(iv)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(v)

The time-period during the Delivery Period for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice; and

(vi)

The date of the upcoming Auction pursuant to which the Auction Settlement Price necessary to calculate the GHG Compliance Costs will be based.

After (1) Seller receives such Required Payment Notice or Optional Payment Notice, and (2) the Auction Settlement Price necessary to calculate such GHG Compliance Costs is published, Seller shall calculate and include as part of the upcoming single regular monthly invoice to Buyer under this Confirmation (and in no event as an invoice that is separate or distinct from such regular monthly invoice), such GHG Compliance Costs. After Buyer’s receipt of such invoice, Buyer shall pay such GHG Compliance Costs along with all other payments due under such invoice in accordance with Article 6 of the Transition Master Agreement. (d)

Seller shall deliver to Buyer a Free Allowance Notice within twenty (20) calendar days of Seller or the Generating Unit(s) being allocated any Free Allowances (with such allocation being determined in accordance with the requirements of subparagraphs (i) or (iv) of the definition of Free Allowance Notice, as applicable, including, without limitation, the requirement that some or all of an allocation of Free Allowances to Seller’s Affiliates shall, if applicable, be deemed to be allocated to Seller). Notwithstanding anything to the contrary set forth in this Section 20.4, to the extent not previously applied, Buyer shall have the right to apply such Free Allowances or the value thereof (as disclosed in the Free Allowance Notice(s)), as applicable, in order to reduce Buyer’s compensation of Seller pursuant to Section 20.4(b) and/or Section 20.4(c) at any time during the Term regardless of when such Free Allowances are allocated (or deemed allocated) to Seller.

(e)

Seller acknowledges and agrees that: (i)

Upon Buyer’s conveyance and delivery of Allowances and/or Offset Credits in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)) or Buyer’s payment to Seller of the GHG Compliance Costs in accordance with Section 20.4(c), or any combination thereof, Buyer shall have fulfilled its obligation under this Confirmation to compensate Seller for the Compliance Obligation deemed imposed on Seller with respect to the Generating Unit(s) during the applicable time-periods set forth in the Transfer Notice(s), Required Payment Notice(s) and/or Optional Payment Notices, and that Buyer is not in any way liable for Seller’s failure to satisfy its Compliance Obligation or otherwise comply with AB 32 or the GHG Regulations; and

(ii)

Title to, and risk of loss, invalidation, cancellation or removal of each Allowance and/or Offset Credit conveyed and delivered to Seller by Buyer (including, without limitation, any such loss, invalidation, cancellation or removal of an Allowance and/or Offset Credit as a result of an action by an authorized Governmental Authority in accordance with the GHG Regulations) transfers from Buyer to Seller upon Buyer’s conveyance and delivery to Seller of each such Allowance and/or Offset Credit in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)); provided that, if (1) any Offset Credits transferred by Buyer to Seller are invalidated pursuant to the GHG Regulations after the date of such transfer, (2) Seller has not sold or otherwise transferred such Offset Credits

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to a third party, other than to the Governmental Authority or other entity authorized to implement the regulatory program on behalf of the Governmental Authority in satisfaction of Seller’s compliance obligation (a “Compliance Transfer”), and (3) except in the case of a Compliance Transfer, Seller demonstrates to Buyer’s reasonable satisfaction that it retains title to such invalidated Offset Credits, then to the extent such Offset Credits or other compliance instruments are still required in order for Seller to satisfy the original compliance obligation for which the Offset Credits were transferred by Buyer to Seller, Buyer shall compensate Seller in accordance with and subject to Sections 20.4 through 20.9 for such invalidated Offset Credits to the extent necessary for Buyer to have satisfied, with respect to such invalidated Offset Credits, its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period. 20.5

Limitation of Liability

Notwithstanding anything to the contrary in the Agreement, Buyer is not responsible for:

20.6

20.7

(a)

Any Compliance Obligation imposed on Seller or the Generating Unit(s), providing any Allowances and/or Offset Credits, or paying any GHG Compliance Costs, to the extent any or all of the aforementioned are associated with Greenhouse Gas emissions that exceed the GHG Cap, that occur outside of the Delivery Period, and/or that result from a Non-SCE Dispatch;

(b)

Any taxes, fees and/or other charges implemented by and imposed upon Seller or the Generating Unit(s) pursuant to Title 17 of the California Code of Regulations, Section 95200, et. seq. (AB 32 Cost of Implementation Fee Regulation), or any similar taxes, charges and/or fees imposed on the Generating Unit(s) or Seller; or

(c)

Any taxes, fees, charges and/or other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to any generating unit that is not a Generating Unit.

Greenhouse Gas Compliance Covenants (a)

Seller covenants that (i) from the commencement of the Delivery Period until the end of the Term, it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation, and (ii) throughout the Term, it shall comply with all requirements applicable to Seller and/or the Generating Unit(s) under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation.

(b)

Buyer covenants that (i) from the commencement of the Delivery Period until the end of the Term it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation, (ii) throughout the Term, it shall comply with all requirements applicable to Buyer under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation, (iii) it shall convey and deliver the Allowances and/or Offset Credits to Seller free from all liens, claims, security interests and defects in title, (iv) each Allowance and/or Offset Credit conveyed and delivered to Seller pursuant to this Confirmation (1) will be, at the time it is conveyed and delivered, validly issued and in force in accordance with the GHG Regulations, and (v) it will havewill have been assigned a Vintage Year (as defined in the GHG Regulations) that allows it to be retired during the applicable Compliance Period in accordance with the GHG Regulations, and (2) may be utilized by Seller for compliance with AB 32 and/or the GHG Regulations then in effect, (v) it will have, at the time conveyed and delivered good and marketable title to each Allowance and/or Offset Credit conveyed and delivered to Seller, and that it will obtain and possess at the time conveyed and delivered, each such Allowance and/or Offset Credit lawfully.

Liquid Market for Allowances

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If, at any time before the expiration of the Delivery Period, a liquid market for Allowances develops wherein price quotes for Allowances can be obtained, the Parties agree to work in good faith to amend this Confirmation to include a methodology for calculating the GHG Compliance Costs for this Transaction using such price quotes. 20.8

Suspension, Repeal or Supersedence of AB 32; Change in AB 32

Notwithstanding anything to the contrary in the Agreement, if AB 32 is suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then, as of the effective date of such suspension, repeal or supersedence, Sections 20.4 through 20.8 will no longer be in force or effect on a going forward basis; provided that subject to and in accordance the terms of the Agreement, Buyer shall be liable to Seller for compensating Seller for Seller’s Compliance Obligation, if any, imposed on Seller for the Generating Unit(s) before such suspension, repeal or supersedence. To the extent Buyer has provided compensation to Seller pursuant to Sections 20.4(b) and 20.4(c) to cover an expected Compliance Obligation under AB 32 and that obligation is subsequently suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then Seller shall return any such compensation in a timely manner to Buyer. If a Change in AB 32 occurs, then either Party, on notice, may request the other Party to enter into negotiations to make the minimum changes to this Confirmation necessary to preserve to the maximum extent possible the balance of benefits, burdens and obligations set forth in this Confirmation as of the Confirmation Effective Date. Upon receipt of a notice requesting negotiations, the Parties shall negotiate in good faith. If the Parties are unable, within sixty (60) days after the sending of the notice requesting negotiations, either to agree upon changes to this Confirmation or to resolve issues relating to changes to this Confirmation, then either Party may submit issues pertaining to changes to this Confirmation to dispute resolution as provided in Section 10.6 of the Transition Master Agreement. In addition to any notices provided above, Seller shall provide notice to SCE as soon as practicable in the event that Seller believes a Change in AB 32 has occurred. 20.9

Exposure Calculation (a)

Subject to any restrictions set forth in the Agreement (including, without limitation, Section 15.1 and Section 20.5 of this Confirmation), the Parties agree that for purposes of calculating Seller’s Exposure to Buyer in respect of a Transaction under the Confirmation, such calculation shall include Buyer’s obligation to compensate Seller for the Compliance Obligation imposed on Seller for the Generating Unit(s) during the Delivery Period to the extent that such obligation is owed or otherwise accrued and payable (regardless of whether such amounts have been or could be invoiced) to Seller and remains unpaid as of the Calculation Date.

(b)

Seller’s Exposure to Buyer in respect of a Transaction under this Confirmation shall be calculated by multiplying (i) the most recent published ICE OTC Physical Environmental Settlements CCA Index Price for the appropriate vintage (e.g., Dec 2013, Dec 2014) immediately preceding the Calculation Date by (ii) the number of metric tons of Greenhouse Gas emitted by and attributable to the Generating Unit(s) for which Buyer has not compensated Seller pursuant to the Confirmation, with such number to be determined in accordance with subparagraph (ii) of the definition of GHG Compliance Costs (rounded up to the nearest metric ton) set forth in the Confirmation.

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ACKNOWLEDGED AND AGREED TO AS OF [________________], 2011: [Seller] OCTOBER 15, 2012: Kern River Cogeneration Company

Southern California Edison Company

By:

By:

Name:

Name:

Title: Neil Burgess

Title: Name: Marc L. Ulrich

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

Date:

Date:

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APPENDIX A DEFINITIONS UNLESS OTHERWISE DEFINED IN THE TRANSITION MASTER AGREEMENT AND ATTACHMENTS, CAPITALIZED TERMS SHALL BE USED WITH THE MEANINGS ASCRIBED TO THEM IN THE TARIFF. AB 32: The California Global Warming Act of 2006, Assembly Bill 32 (2006) and the regulations promulgated thereunder (including, without limitation, the GHG Regulations) by any authorized Governmental Authority. Accepted Electrical Practices: Those practices, methods, applicable codes, and acts engaged in or approved by a significant portion of the electric power industry during the relevant time period, or any of the practices, methods, and acts which, in exercise of reasonable judgment in light of the facts known at the time a decision is made, could have been expected to accomplish a desired result at reasonable cost consistent with good business practices, reliability, safety, and expedition. Accepted Electrical Practices are not intended to be limited to the optimum practices, methods, or acts to the exclusion of other, but rather to those practices, methods, and acts generally accepted, or approved by a significant portion of the electric power industry in the relevant region, during the relevant time period, as described in the immediately preceding sentence. Adjustment Gas Cost: As set forth in Section 3.1(ed)(viii) of this Confirmation. Adjustment Gas Quantity: As set forth in Section 3.1(ed)(v) of this Confirmation. ADS: The Automatic Dispatch System, or its successor. Air Pollution Control District: A district as defined by Section 39025 of the California Health and Safety Code, Division 26, Air Resources. Allowance: (i) CA GHG Allowance, as such term is defined in the GHG Regulations, or (ii) an allowance specified in Section 95942(b) of the GHG Regulations and approved by the CARB pursuant to Section 95941 of the GHG Regulations. Ancillary Services: As set forth in the Tariff. Ancillary Services Capacity: For each applicable Ancillary Service, the Ancillary Service available to SCE within the scope of operations allowed SCE under this Confirmation pursuant to Section F of Appendix 1.4, plus any other interconnected operation services that the CAISO develops or deems as Ancillary Services. Applicable Laws: Means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Authority having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. A/S Availability: The amount of Ancillary Services Capacity available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. A/S Maximum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the maximum capacity for a particular region in which such Ancillary Service is available. A/S Minimum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the minimum capacity for a particular region in which such Ancillary Service is available.

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Auction: Each auction for Allowances conducted in accordance with Subarticle 10 of the GHG Regulations, except for the first auction identified in Section 95910(a)(1) of the GHG Regulations. Auction Settlement Price: As set forth in the GHG Regulations. Automatic Generation Control or AGC: output.

The remote signal control of a Generating Unit’s megawatt

Availability Incentive Payments: As set forth in the Tariff. Availability Notice: As set forth in Section 9.1 of this Confirmation. Availability Standards: As set forth in the Tariff. Available Capacity: The amount of Contract Capacity that is available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. If a Generating Unit’s Available Capacity during any Settlement Interval is below PMin, then the Available Capacity shall be deemed zero for such Settlement Interval. Black Start: As set forth in the Tariff. Boiler or Boiler Unit: Conventional steam cycle. CAISO: The California Independent System Operator or any successor entity performing the same functions. CAISO Grid: The system of transmission lines and associated facilities of the Participating Transmission Owners that have been placed under the CAISO’s operational control. Capacity: Exclusive of any Resource Adequacy Benefits, the maximum dependable operating capability of any generating resource to produce or generate Energy and any other products that may be developed or evolve from time to time that relate to the capability of a generating resource to produce or generate Energy. Capacity Availability: For each Settlement Interval (i) the Generating Unit’s Available Capacity, if the Generating Unit operates within the Performance Tolerance Band, or (ii) the Generating Unit’s Available Capacity, less the product of (x) the difference between (a) Scheduled Energy minus (b) Qualifying Delivered Energy, and (y) the number of Settlement Intervals in one hour, if the Generating Unit operates below the Performance Tolerance Band Lower Limit. In no event shall the Capacity Availability be less than zero MW nor greater than the Contract Capacity for the Generating Unit. CARB: California Air Resources Board, or any successor entity. CCGT: Combined cycle gas turbine. Change in AB 32: A change in AB 32 after the Confirmation Effective Date, which change has a material impact on either party with respect to a Compliance Obligation under Article 20 with respect to the electric energy produced, sold or purchased pursuant to this Confirmation. A Change in AB 32 may include, for example, a change in exemptions or the calculation of compliance obligations, but will not include an increase or decrease in the cost of Allowances or Offset Credits. CHP: As set forth in Article 5 of this Confirmation. Compliance Obligation: As set forth in the GHG Regulations.

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Compliance Period: As set forth in the GHG Regulations. Compliance Transfer: As set forth in Section 20.4(e)(ii) of this Confirmation. Contract Capacity: As set forth in Section A of Appendix 1.4 of this Confirmation, the Quantity of Capacity that Seller is committing to provide to SCE pursuant to this Confirmation. Contract Year: The twelve (12) months within each calendar year from the Confirmation Effective datestarting with the beginning of the Delivery Period until the termination of this Confirmation. CPUC: The California Public Utilities Commission or any successor thereto. CPUC Approval: Either (1)Means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, or (2) a final and non-appealable disposition of the CPUC’s Energy Division, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation and the, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA in their respective entirety, including payments to be made by SCEBuyer, subject to CPUC review of SCEBuyer’s administration of each of this Confirmation and the, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and nonappealable. Crossing Time: Forbidden Region Crossing Time, as set forth in the “Definition” tab of the CAISO Master File. CT: Combustion turbine. Day-Ahead Gas Cost: As set forth in Section 3.1(ed)(vii) of this Confirmation. Day-Ahead Gas Quantity: As set forth in Section 3.1(ed)(iv) of this Confirmation. Delivered Energy: With respect to a Generating Unit and during the Delivery Period, the amount of Energy generated by such Generating Unit and delivered during each Settlement Interval at the Energy Delivery Point as measured by the Energy Metering Equipment, and subject to adjustments identified in this Confirmation. The Delivered Energy in any hour is equal to the sum of the Delivered Energy for each Settlement Interval during such hour. Delivery Period: The period of time commencing on and including the earliest date set forth in the column entitled “Contract Year Start Date” in Appendix 3.1(a), and ending on and including the latest date set forth in the column entitled “Contract Year End Date” in Appendix 3.1(a).Has the meaning specified in Section 1.4 of this Confirmation. Disclosure Schedule: As set forth in Section 13.3(c) of this Confirmation. Dispatch Data: As set forth in Article 17 of this Confirmation. Dispatch Notice: The operating instruction, and any subsequent updates given by SCE to Seller, directing the applicable Generating Unit to operate at a specified megawatt output or a dispatch given by the CAISO under Section 9.3. Dispatch Notices may be communicated electronically (i.e., through ADS), via e-mail, via facsimile, telephonically, or by other verbal means. Telephonic or other verbal communications shall be documented (either recorded by tape, electronically or in writing) and such recordings shall be made available to both SCE and Seller upon request for settlement purposes. Distributed Control System or DCS: The integrated automation system for monitoring and controlling the

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critical operation functions of a facility that performs tasks essential to the generation of electricity. Emission Reduction Credits or ERC(s): Emission reductions that have been authorized by a local air pollution control district pursuant to California Division 26 Air Resources; Health and Safety Code Sections 40709 and 40709.5, whereby a district has established a system by which all reductions in the emission of air contaminants that are to be used to offset certain future increases in the emission of air contaminants shall be banked prior to use to offset future increases in emissions. Energy: All electrical energy produced, flowing, or supplied by a Generating Unit less the Station Use, measured in kilowatt-hours or multiples units thereof. Energy shall include without limitation any energy associated with Capacity, Ancillary Services, and any other electrical energy product that may be developed or evolve from time to time during the Term. Energy Delivery Point: The point on the CAISO grid defined in Appendix 1.6 of this Confirmation. Energy Metering Equipment: For each Generating Unit, the meters and measuring equipment certified by the CAISO for such Generating Unit, and which measures the Delivered Energy of such Generating Unit. Environmental Costs: Costs incurred in connection with acquiring and maintaining all environmental permits and licenses for the Generating UnitUnits, and the Generating Unit’s compliance with all applicable environmental laws, rules and regulations, including capital costs for pollution mitigation or installation of emissions control equipment required to permit or license the Generating UnitUnits, all operating and maintenance costs for operation of pollution mitigation or control equipment, costs of permit maintenance fees and emission fees as applicable, and the costs of all Emission Reduction Credits or Marketable Emission Trading Credits required by any applicable environmental laws, rules, regulations, and permits to operate, and costs associated with the disposal and clean-up of hazardous substances introduced to the Generating Unit site, and the decontamination or remediation, on or off the Generating Unit site, necessitated by the introduction of such hazardous substances on the Generating Unit site. Envoy: SoCalGas’ internet based electronic bulletin board (called “Envoy”) that monitors electronic gas transactions and serves as SoCalGas’ information management computer system. Exempt Wholesale Generator: An unregulated power generator that is allowed to sell wholesale power as an independent energy producer, and is exempt from the Public Utility Holding Company Act of 1935. Exposure: As set forth in the Transition Collateral Annex. Failed Test: As set forth in Section 10.2 of this Confirmation. FERC Approval: Means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at marketbased rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. Final Test Plan: As set forth in Appendix 10.2 of this Confirmation. Forbidden Operating Region: As set forth in the Tariff.

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Forced Outage: As set forth in the Tariff. Free Allowance: Authority.

Any Allowance freely allocated by the CARB or another authorized Governmental

Free Allowance Notice: The notice delivered by Seller to Buyer in accordance with Section 20.4(d), which notice shall set forth: (i) The aggregate quantity of Free Allowances allocated by the CARB (and/or any other Governmental Authority) to Seller, any of Seller’s Affiliates, and/or the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof); and (ii) Any documentation from the CARB (and/or any other Governmental Authority) relating to such allocation. If the CARB (and/or any other Governmental Authority) allocates Free Allowances to Seller (and/or any of Seller’s Affiliates), but does not specifically allocate such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), then the notice described in this definition shall set forth: (iii) The aggregate quantity of Free Allowances allocated to Seller and/or any of Seller’s Affiliates by the CARB (and/or any other Governmental Authority), and all documentation from the CARB (and/or any other Governmental Authority) relating to such allocation; (iv) The number of Free Allowances that shall be deemed allocated to Seller and/or the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), which number Seller shall calculate: (1) By utilizing the then-effective methodology established by the CARB (and/or any other Governmental Authority) relating to such allocation, including, without limitation, any methodology that would apportion a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, Covered Entities and/or Opt-in Covered Entities (as each term is defined in the GHG Regulations)) that could be allocated such Free Allowances; or (2) If the CARB (and/or other Governmental Authority) has not established such a methodology, by apportioning a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, oil refineries and/or other industrial process plants) that could be allocated such Free Allowances; and (v) All documentation reasonably necessary to support the methodology set forth in subparagraph (iv)(1) and/or (iv)(2) of this definition, which shall include, without limitation, any documentation reasonably requested by Buyer to verify Seller's methodology and calculations after Buyer’s receipt of such notice. Fuel Payment: As set forth in Section 3.1(e)d) of this Confirmation. Full Floating Independent Amount: As set forth in Section 15.2 of this Confirmation. Full Load: As set forth in Appendix 10.2 of this Confirmation.

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GADS: The Generating Availability Data System, or its successor. Gas Commodity Costs: As set forth in Section 3.1(ed)(vi) of this Confirmation. Gas Day: As defined in the applicable tariff of the gas transporter supplying the Generating Unit. Gas Index: As defined in Section 3.1(ed)(i) of this Confirmation. Gas Trading Day: As set forth in Section 3.1(d)(ii) of this Confirmation. Generating Facility: Power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. The Generating Facility shall include the Generating Units. Generating Unit: The generating unit or units specified in Appendix 1.8 of this Confirmation. References to Generating Units shall be applicable only to Generating Unit # 1 and Generating Unit # 3 throughout the Delivery Period. Generating Unit # 1: The Generating Unit described in Section 1.a. of Appendix 1.8 of this Confirmation. Generating Unit # 3: The Generating Unit described in Section 1.b. of Appendix 1.8 of this Confirmation. Generation Operations Center or GOC: The location of SCE’s Real Time operations personnel. Generation Management System or GMS: The automated system employed by SCE real time operations to remotely monitor, dispatch, and control each Generating Unit. Generator Operator: The entity that operates generating unitthe Generating Unit(s) and performs the functions of supplying energy and interconnected operations services as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. Generator Owner: The entity that owns and maintains generating unitsthe Generating Unit(s) as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. GHG Calculation: As set forth in Section 20.3 of this Confirmation. GHG Cap: The GHG Rate times the Required Natural Gas Quantity associated with a Dispatch Notice. GHG Charges: As set forth in Section 20.2 of this Confirmation. GHG Compliance Cost: The dollar amount calculated by multiplying: (i) The cost of one Allowance, determined using the published Auction Settlement Price from the last Auction to have taken place before the date that Buyer’s payment is due to Seller in accordance with Section 20.4(c); by (ii) The number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) during the applicable time-period, which number is determined by multiplying the GHG Rate by the Required Natural Gas Quantity for each calendar day during the applicable time-period; provided that if Buyer determines to compensate Seller for a portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) by providing Seller with Allowances and/or Offset Credits in accordance with Section 20.4(b), the factor set forth in this subparagraph (ii) will be reduced by the number of metric tons of Greenhouse Gas emissions (rounded up to the nearest metric ton) for which Buyer provides such Allowances and/or Offset Credits.

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GHG Credits: As set forth in Section 20.3(a)(i) of this Confirmation. GHG Documentation: As set forth in Section 20.2 of this Confirmation. GHG Rate: The rate for pounds of Greenhouse Gas emissions per MMBtu of natural gas, 117 lbs of Greenhouse Gas emissions /MMBtu, as derived through information provided in the Energy Information Administration’s Documentation for Emissions of Greenhouse Gases in the United States 2005 (DOE/EIA-0638) http://www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2005).pdfhttp://www.eia.doe.gov/oiaf/160 5/ggrpt/documentation/pdf/0638(2005).pdf and the Environmental Protection Agency’s Emission Factors, AP 42, Fifth Edition, Volume I http://www.epa.gov/ttn/chief/ap42/index.htmlhttp://www.epa.gov/ttn/chief/ap42/index.html. GHG Regulations: Subchapter 10 Climate Change, Article 5, Sections 95800 to 96022, Title 17, California Code of Regulations, as amended or supplemented from time to time. Governmental Authority: Any federal, state, local, municipal, or other governmental, executive, administrative, judicial, or regulatory entity, and the CAISO or any other transmission authority, having or asserting jurisdiction over a Party, any Generating Unit or this Confirmation. Green Attributes: Any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1

(3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program.

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(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. Greenhouse Gas: As set forth in the GHG Regulations. Heat Rate: The amount of natural gas in MMBtu required to produce one MWh of Energy. Historical Outage Report: As set forth in Section 13.3(bd) of this Confirmation. Holiday: New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, or Christmas Day. When any Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. Host Site: The site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Affiliates located at such site. IE: As set forth in Section 13.2(b) of this Confirmation. IFA or Interconnection Facilities Agreement: Any agreement between the Seller and its Participating Transmission Owner providing for the transmission of electrical energy from the Generating Unit to the Pointpoint of Interconnectioninterconnection. IFM or Integrated Forward Market: As set forth in the Tariff. Industry Standards: As set forth in Section 13.1 of this Confirmation. Lower MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Marketable Emission Trading Credits: Without limitation, emissions trading credits or units pursuant to the requirements of California Division 26 Air Resources; Health & Safety Code Section 39616 and Section 40440.2 for market based incentive programs such as the South Coast Air Quality Management District’s Regional Clean Air Incentives Market, also known as RECLAIM, and allowances of sulfur dioxide trading credits as required under Title IV of the Federal Clean Air Act (see 42 U.S.C. § 7651b.(a) to (f)). Master File: As set forth in the Tariff. Maximum Daily Start-Ups: As set forth in the Tariff. MCP or Market Clearing Price: For each Settlement Interval, the Day-Ahead Market price for the hour in which such Settlement Interval falls for the SP15 EZ Gen Hub. Minimum Down Time: As set forth in the Tariff. Minimum Load: As set forth in the Tariff.

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Minimum Run Time: As set forth in the Tariff. Monthly Capacity Payment: As set forth in Appendix 3.1(a), but subject to Article 3 of this Confirmation. MSA or Meter Service Agreement: Scheduling Coordinator Meter Service Agreement. MSG Transition: As set forth in FERC filing ER10-1360 or as modified and approved by FERC thereafter to be incorporated in the Tariff or otherwise applicable to CAISO. Natural Gas Requirements: All of the Generating UnitsUnit’s natural gas requirements, including the Required Natural Gas Quantity, natural gas for any Non- SCE Dispatch and natural gas for any other purpose. NERC/GADS Protocols: The GADS protocols established by NERC, as may be updated from time to time. NERC Holidays: “Additional Off-peak Days” as defined by NERC on the NERC website at http://www.nerc.comhttp://www.nerc.com. NERC Reliability Standards: Those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by NERC and approved by the applicable regulatory authorities and and available on the NERC website. Non-Availability Charges: As set forth in the Tariff. Non-SCE Dispatch: A dispatch by Seller either (a) pursuant to a Seller Initiated Test or (b) as required by Applicable Laws. Non-Spinning Reserve: As set forth in the Tariff. Offset Credit: As set forth in the GHG Regulations. Operating Day: A day within the Delivery Period on which the Generating Unit operates. Operating Level: As set forth in the “Definition” tab of the CAISO Master File. Operating Reserve Ramp Rate: As set forth in the Tariff. Operating Restriction: Limitations on SCE’s ability to schedule and use Capacity, Ancillary Services, and Energy for each Generating Unit subject to this Confirmation that are identified in Appendix 1.4. Operational Ramp Rate: As set forth in the Tariff. Optional Payment Notice: As set forth in Section 20.4(c). Optional Transfer Date: The first (1st) Business Day of the month in which an Auction during the Delivery Period takes place, not including Transfer Date 2 or Transfer Date 3. Outage: As set for in the Tariff. Outage Management System: As set forth in Section 9.1 of this Confirmation. Outage Schedule: As set forth in Section 11.1 of this Confirmation. Pacific Prevailing Time or PPT: Pacific Daylight Time when California observes Daylight Savings Time

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and Pacific Standard Time otherwise. Participating Transmission Owner: A transmission owner which has released operational control of its transmission facilities to the CAISO. Performance Tolerance Band: The higher of (a) three percent (3%) of a Generating Unit’s PMax divided by the number of Settlement Intervals in an hour, (b) five (5) MW divided by the number of Settlement Intervals in an hour, or (c) the applicable Regulation Award divided by the number of Settlement Intervals in an hour. If, at any time, the CAISO implements changes to the Performance Tolerance Band, then the Parties agree to negotiate in good faith to amend this definition to maintain the economic benefits and burdens contemplated under this Confirmation. Performance Tolerance Band Lower Limit: A quantity of Energy determined for a Settlement Interval equal to Scheduled Energy minus the Performance Tolerance Band. Performance Tolerance Band Upper Limit: A quantity determined for a Settlement Interval equal to Scheduled Energy plus the Performance Tolerance Band. Permit Requirements: Any requirement or limitation imposed as a condition of a permit or other authorization relating to construction or operation of the Generating Units subject to the obligations of this Confirmation or related facilities, including limitations on any pollutant emissions levels, limitations on fuel combustion or heat input throughput, limitations on operational levels or operational time, limitations on any specified operating constraint, requirements for acquisition and provision of any Emission Reduction Credits or Marketable Emission Trading Credits; or any other operational restriction or specification related to compliance with any Applicable Laws. PGA or Participating Generator Agreement: As set forth in the Tariff. Planned Outage: As set forth in the applicable CPUC Decisions, namely a planned, scheduled, or any other Outage for the routine repair or maintenance of the UnitGenerating Units, or for the purposes of new construction work, and does not include any Outage designated as either forced or unplanned as defined by the CAISO or NERC/GADS Protocols. PMax: As defined in the Tariff. The value of PMax is specified in Appendix 1.4 of this Confirmation. PMin: Minimum Load. Power Rating: The electrical power output value indicated on the generating equipment nameplate. Present Value: The value on a given date of a future payment or series of future payments, discounted using the appropriate yield curve based on the U.S. Treasury constant maturities securities as posted by the Federal Reserve in their H.15 daily update at the following address: http://www.ustreas.gov/offices/domestic-finance/debt-management/interest-rate/yield.html. Product: As set forth in Section 1.5 of this Confirmation. Project: The Generating Facility. Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Protective Apparatus: The control devices (such as meters, relays, power circuit breakers and synchronizers) specified in the Interconnection Facilities Agreement for the Generating Unit.

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PTC 22: The performance test code entitled “PTC-22-2005 - Gas Turbines," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PTC 46: The performance test code entitled “PTC 46-1996 - Overall Plant Performance," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PURPA: The Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. Qualifying Delivered Energy: The lesser of Delivered Energy or the Performance Tolerance Band Upper Limit for each Settlement Interval during the Delivery Period. Qualifying Delivered Energy shall be zero (0) (i) during a Seller Initiated Test; (ii) during a Non-SCE Dispatch; (iii) if the Delivered Energy is less than PMin minus the Performance Tolerance Band; or (iv) during a Start-Up. Qualifying Facility: An electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of self-certification pursuant to 18 CFR Part 292.207(a). Quantitative Usage Limit: As set forth in the GHG Regulations. RA Confirmation: That certain Resource Adequacy Confirmation dated herewith between Seller and SCE, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. Reduced Monthly Capacity Payment: As set forth in Section 3.2(c) of this Confirmation. Regulation Award: For each Settlement Interval, shall mean either (i) with respect to the Performance Tolerance Band Upper Limit, the greater of the fifteen-minute HASP Regulation Up awards for the period within such Settlement Interval falls, or (ii) with respect to the Performance Tolerance Band Lower Limit, the greater of the fifteen-minute HASP Regulation Down awards for the period within such Settlement Interval falls. Regulation Down: As set forth in the Tariff. Regulation Ramp Rate: As set forth in the Tariff. Regulation Up: As set forth in the Tariff. Renewable Energy Credit: As set forth in Public Utilities Code Section 399.12(h), as may be amended from time to time or as further defined or supplemented by applicable law. Repair Plan: As set forth in Section 13.2(b) of this Confirmation. Required Natural Gas Quantity: As set forth in Section 3.1(ed)(iii) of this Confirmation. Required Payment Notice: As set forth in Section 20.4(c). Resource Adequacy Benefits: The rights and privileges attached to any generating resource that satisfy any entity’s resource adequacy obligations or requirements under any CPUC Decisions 04-01-050, 0410-035, 05-10-042, 06-04-040, 06-06-064, 06-07-031, and 07-06-029 and/or any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or

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promulgated by any applicable Governmental Authority, as such decisions, rulings, laws, rules, or regulations may be amended or modified from time to time. Resource Adequacy Resource: As set forth in the Tariff. RMR Settlement Coordinator: As set forth in Section 7.2 of this Confirmation. RMR Invoice: As set forth in Section 7.2 of this Confirmation. RMR Revenue: As set forth in Section 7.2 of this Confirmation. Satellite Communications System or SCS: A system provided to Seller by SCE at SCE’s cost for emergency voice communications between SCE and Seller’s operating staff for the Generating Units. SCE Annual Test: As set forth in Section 10.2 of this Confirmation. SCE Dispatched Test: As set forth in Section 10.1 of this Confirmation. SCE Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Scheduled Energy: The Energy from a Generating Unit expected to be delivered during each Settlement Interval to the Energy Delivery Point pursuant to (a) the latest Dispatch Notice, or (b) any CAISO instructions during the Delivery Period, including (i) supplemental energy bids, or (ii) Ancillary Services exercised. If, in any Settlement Interval, the expected energy normally published by CAISO is unavailable, incomplete, or does not conform to the Operating Restrictions of the Generating UnitUnits, then for settlement purposes for that Settlement Interval only, the Scheduled Energy shall be deemed to be the Delivered Energy. Scheduling Coordinator or SC: As set forth in the Tariff. SC Replacement Date: As set forth in Section 6.4 of this Confirmation. SDD Administration Charge: As set forth in Section 8.4 of this Confirmation. SDD Admin Price: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term as defined in the Tariff. SDD Charge: A scheduling and delivery deviation charge as set forth in Section 8.3 of this Confirmation. SDD Price: For each Generating Unit, the Resource-Specific Settlement Interval LMP (as defined in the MRTU's Tariff Appendix A – “Definitions”) or any equivalent price under MRTU. In no case shall the SDD Price be less than zero (0). Self-Schedule: As set forth in the Tariff. Seller Initiated Test: As set forth in Section 10.1 of this Confirmation. Seller’s Fleet: As set forth in Section 20.3(a)(ii) of this Confirmation. Seller’s Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Settlement Agreement: The Qualifying Facility and Combined Heat and Power Program Settlement Agreement approved by the CPUC in Decision 10-12-035 issued on December 21, 2010.2010, effective

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November 23, 2011. Settlement Interval: As set forth in the Tariff. Shape: As set forth in Appendix 1514 of this Confirmation. Shaped Price: Shall be the price of power as determined in accordance with Appendix 1514 of this Confirmation. Site Host: The person or persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating FacilityUnits and the generating units that are subject to the obligations in the Transition PPA. Site Host Load: The electric energy and capacity produced by or associated with the Generating FacilityUnits and the generating units that are subject to the obligations in the Transition PPA that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b). Site Specific Reference Conditions: Shall have the meaning specified in Appendix 10.2 SoCalGas: Southern California Gas Company. SoCalGas Billing Meter: A revenue quality meter owned by SoCalGas (i.e., a meter meeting the standards and requirements established and maintained by SoCalGas) used to measure the quantity of natural gas delivered from the SoCalGas system to the Generating Unit for the purpose of monthly billing by SoCalGas. SoCalGas Tariff: Southern California Gas Company’s tariff filed with the CPUC, as amended or supplemented from time to time. SoCalGas Schedule No. GT-F: Firm Intrastate Transportation Service for Distribution Level Customers as provided by SoCalGas in the SoCalGas Tariff. SoCalGas Schedule No. GT-TLS: Intrastate Transportation Service for Transmission Level Customers as provided by SoCalGas in the SoCalGas Tariff. SoCalGas Transportation Contract: The natural gas transportation agreement between Seller and SoCalGas under either SoCalGas Schedule No. GT-F or SoCalGas Schedule No. GT-TLS for firm priority service in either case with sufficient capacity capable of transporting a full peak day natural gas requirement for an applicable month to each Generating Unit. SP15: The SP15 EZ Gen Hub. If the SP15 EZ Gen Hub (under any name) is not established as part of a market redesign that is implemented after the commencement of the Term, an alternative trading zone may be mutually agreed upon by the Parties in good faith that reasonably approximates the characteristics of the Existing Zone region of SP15. SP15 EZ Gen Hub: As set forth in the Tariff. Spinning Reserve: As set forth in the Tariff. Start-Up: Resulting only from a Dispatch Notice, the action of bringing the Generating Unit from shut down status to synchronization with the grid, attainment of its PMin, and the availability of unconditional release of such Generating Unit ready for ramping to the applicable dispatch instruction. Start-Up Aux Energy: The applicable amount of energy (MWh) required to Start-Up the Generating Unit

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specified in Appendix 3.1(c) of this Confirmation. Start-Up Aux Charge: The product of the applicable Start-Up Aux Energy and the sum of the “energy charge” rates (under the column headers “Delivery Service” and “Generation”) set forth in [SCEPG&E Tariff Rate Schedule TOU-8S for “Standby Service Metered and Delivered at Voltages above 50 kV at Transmission Service Voltage”] applicable to the appropriate “peak” period and in effect at the time of the applicable Start-Up. If a Start-Up falls within multiple “peak” periods (on-peak, mid-peak, or off-peak), then the Start-Up Aux Charge shall be calculated by applying the applicable “energy charge” rates to the Start-Up Aux Energy amount proportional to amount of time elapsed under each applicable “peak” period. Start-Up Charge: The applicable charge ($) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Fuel: The applicable volume of natural gas (MMBtu) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Notice: As set forth in Section 9.2(b) of this Confirmation. Start-Up Time: The applicable amount of time (minutes) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Station Use: The electrical load of the Generating Unit’s auxiliary equipment. The auxiliary equipment includes forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems, control systems, and sump pumps. Substitution Cost: As set forth in Section 6.5 of this Confirmation. Substitution Rules: As set forth in Section 6.5 of this Confirmation. Successful Repair: Immediately upon completion of the repairs to a Generating Unit, Seller demonstrates, at Seller’s expense, to SCE’s reasonable satisfaction, that such Generating Unit can: (i) Start-Up and ramp up to and remain at full load for two (2) consecutive hours, and (ii) immediately thereafter remain available to generate Energy under this Confirmation by a quantity greater than or equal to ninety-eight percent (98%) of Contract Capacity for seven (7) consecutive days. Supply Plan: As set forth in the Tariff. Tariff: The tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. Term: As set forth in Section 1.3 of this Confirmation. Test Parameters: Shall have the meaning specified in Appendix 10.2 Trading Day: The day in which Day Ahead trading occurs in accordance with the WECC Preschedule Calendar. Transfer Date 1: The first (1st) Business Day of the month in which the Auction immediately following the end of the Delivery Period is to take place. Transfer Date 2: The first (1st) Business Day of the month in which the Auction immediately following the end of each year during the Delivery Period that Seller must satisfy its annual

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compliance obligation (as described in Section 95855 of the GHG Regulations) is to take place. Transfer Date 3: The first (1st) Business Day of the month in which the Auction immediately following the end of the applicable Compliance Period is to take place, if such Compliance Period ends during the Delivery Period. Transfer Notice: As set forth in Section 20.4(b)(v). Transmission Owner: As set forth in the Tariff.

Transition Cost: The applicable fixed cost ($) required for the Generating Unit to make an MSG Transition as set forth in Appendix 3.1(c) under the heading “Fixed Transition Cost ($)”.:”. Transition Fuel: The applicable volume of natural gas (MMBtu) required for the Generating Unit to make an MSG Transition as set forth in Appendix 3.1(c) under the heading “Transition Fuel (MMBtu):”.PPA: As set forth in the Transition Cover Sheet. Transport Cost: As set forth in Section 3.1(e)(ix) of this Confirmation.Transition RA Confirmation: That certain Resource Adequacy Confirmation dated herewith between Seller and SCE, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. Turbine Configuration: As set forth in Appendix 1.8 of this Confirmation. UDP: Uninstructed Deviation Penalty, as applied to each SC by the CAISO, or any successor thereto pursuant to the Tariff. Uninstructed Deviation GMC Rate: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term to UIE. Upper MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Variable O&M Charge: As set forth in Appendix 3.1(b) of this Confirmation. Variable O&M Payment: As set forth in Section 3.1(b) of this Confirmation. WECC Preschedule Calendar: The Preschedule Calendar(s) as set forth or described on the WECC website at http://www.wecc.biz.

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APPENDIX 1.4 CONTRACT CAPACITY, ANCILLARY SERVICES AND OPERATING RESTRICTIONS Technology:

COMBUSTION TURBINE

Generating Unit Name:

Kern River Cogeneration Company Unit 1

A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information Minimum Load, PMin (MW):

70.00

PMax (MW):

78.00

Max capacity w/o duct burners (MW):

78.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Daily Run Hours

No

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

78.00

1.00

Best Operational Minimum Down Ramp Rate Time (minutes): (MW/min) 3.00

60.00

Minimum Run Time (minutes):

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Yes Ancillary Services are included: Yes KRCC is not currently included in Black Start Capability Plan Black Start included: Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

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Technology:

COMBUSTION TURBINE Kern River Cogeneration Company Unit 3

Generating Unit Name: A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information

Minimum Load, PMin (MW):

70.00

PMax (MW):

80.00

Max capacity w/o duct burners (MW):

80.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Daily Run Hours

No

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

80.00

1.00

Best Operational Minimum Down Ramp Rate Time (minutes): (MW/min) 3.00

60.00

Minimum Run Time (minutes):

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Yes Ancillary Services are included: Yes KRCC is not currently included in Black Start Capability Plan Black Start included: Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

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APPENDIX 1.6

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ENERGY DELIVERY POINT

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Single-line diagram of grid interconnection [TO BE PROVIDED BY SELLER] [THE ENERGY DELIVERY POINT AND THE LOCATION OF THE ENERGY METERING EQUIPMENT MUST BE ACCURATELY MARKED ON THE SINGLE-LINE DIAGRAM.]

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APPENDIX 1.8 DESCRIPTION OF GENERATING UNITS AND DESCRIPTION OF SITE 1.

Generating Units Description.

a.

Generating Unit # 1 i.

Name: Kern River Cogeneration Company Unit # 1

ii.

Location: SW China Grade Loop, Bakersfield, California

iii.

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 1

iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: 77.25 MW. v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

b.

xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 77.25

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 101514

Generating Unit # 3 i.

Name: Kern River Cogeneration Company Unit # 3

ii.

Location: SW China Grade Loop, Bakersfield, California

iii.

CAISO Resource ID (as defined in the CAISO Tariff): OMAR_2_Unit 3

iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: 77.25 MW v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

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vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 77.25

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 101514

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

2.

Site Description. Kern River Cogeneration Company Plant Site [TO BE PROVIDED BY SELLER] THAT PORTION OF SECTION 32, TOWNSHIP 28 SOUTH, RANGE 25 EAST, H.D.M., IN THE COUNTY OF KERN. STATE OF CALIFORNIA. DESCRIBED AS FOLLOWS: COMMENCING AT THE NORTHWEST CORNER OF SAID SECTION 32; THENCE SOUTH 00 DEGREES 22 MINUTES 14 SECONDS WEST ALONG THE WEST LINE OF THE NORTHWEST QUARTER OF SAID SECTION 32, A DISTANCE OF 1271.73 FEET; THENCE DEPARTING SAID WEST LINE SOUTH 85 DEGREES 37 MINUTES 46 SECONDS EAST A DISTANCE OF 2219.62 FEET TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION; THENCE (1) N.86 DEG. 36 MIN. 19 SEC E., A DISTANCE OF 88.81 FEET; THENCE (2) N.78 DEG. 25 MIN. 31 SEC E., A DISTANCE OF 36.40 FEET; THENCE (3) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 45.00 FEET; THENCE (4) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 40.00 FEET; THENCE (5) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 120.00 FEET; THENCE (6) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (7) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 13.00 FEET; THENCE (8) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 40.00 FEET; THENCE (9) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 8.00 FEET; THENCE (10) N.10 DEG. 44 MIN. 52 SEC E., A DISTANCE OF 171.06 FEET; THENCE (11) N.18 DEG. 37 MIN. 55 SEC W., A DISTANCE OF 230.31 FEET; THENCE (12) N.13 DEG. 49 MIN. 58 SEC E., A DISTANCE OF 48.66 FEET; THENCE (13) N.41 DEG. 14 MIN. 26 SEC E., A DISTANCE OF 50.00 FEET; THENCE (14) N.56 DEG. 04 MIN. 49 SEC E., A DISTANCE OF 48.41 FEET; THENCE (15) N.77 DEG. 21 MIN. 00 SEC E., A DISTANCE OF 51.24 FEET; THENCE (16) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 43.00 FEET; THENCE (17) S.60 DEG. 42 MIN. 03 SEC E., A DISTANCE OF 156.59 FEET; THENCE (18) N.87 DEG. 20 MIN. 32 SEC E., A DISTANCE OF 73.55 FEET; THENCE (19) S.56 DEG. 34 MIN. 29 SEC E., A DISTANCE OF 30.89 FEET; THENCE (20) S.20 DEG. 32 MIN. 03 SEC E., A DISTANCE OF 30.87 FEET; THENCE (21) S.06 DEG. 54 MIN. 55 SEC W., A DISTANCE OF 225.22 FEET; THENCE (22) S.04 DEG. 22 MIN. 14 SEC W., A DISTANCE OF 90.00 FEET; THENCE (23) S.03 DEG. 11 MIN. 03 SEC W., A DISTANCE OF 95.34 FEET; THENCE (24) S.01 DEG. 19 MIN. 04 SEC W., A DISTANCE OF 75.11 FEET; THENCE (25) S.17 DEG. 07 MIN. 51 SEC E., A DISTANCE OF 35.47 FEET;

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

THENCE (26) S.19 DEG. 37 MIN. 32 SEC W., A DISTANCE OF 34.21 FEET; THENCE (27) S.12 DEG. 52 MIN. 15 SEC E., A DISTANCE OF 30.36 FEET; THENCE (28) S.82 DEG. 43 MIN. 07 SEC E., A DISTANCE OF 59.08 FEET; THENCE (29) S.66 DEG. 18 MIN. 47 SEC E., A DISTANCE OF 102.79 FEET; THENCE (30) N.89 DEG. 14 MIN. 33 SEC E., A DISTANCE OF 78.31 FEET; THENCE (31) N.53 DEG. 27 MIN. 22 SEC E., A DISTANCE OF 19.85 FEET; THENCE (32) N.18 DEG. 54 MIN. 18 SEC E., A DISTANCE OF 27.89 FEET; THENCE (33) N.76 DEG. 33 MIN. 06 SEC E., A DISTANCE OF 29.41 FEET; THENCE (34) N.60 DEG. 40 MIN. 50 SEC E., A DISTANCE OF 14.42 FEET; THENCE (35) N.24 DEG. 01 MIN. 28 SEC E., A DISTANCE OF 29.73 FEET; THENCE (36) S.74 DEG. 54 MIN. 59 SEC E., A DISTANCE OF 37.66 FEET; THENCE (37) N.80 DEG. 20 MIN. 04 SEC E., A DISTANCE OF 49.48 FEET; THENCE (38) S.85 DEG. 37 MIN. 46 SEC E., A DISTANCE OF 20.00 FEET; THENCE (39) S.55 DEG. 03 MIN. 01 SEC E., A DISTANCE OF 25.55 FEET; THENCE (40) S.30 DEG. 37 MIN. 17 SEC E., A DISTANCE OF 24.41 FEET; THENCE (41) S.03 DEG. 13 MIN. 27 SEC E., A DISTANCE OF 30.27 FEET; THENCE (42) S.16 DEG. 11 MIN. 08 SEC E., A DISTANCE OF 42.27 FEET; THENCE (43) S.37 DEG. 28 MIN. 55 SEC W., A DISTANCE OF 109.84 FEET; THENCE (44) S.00 DEG. 13 MIN. 33 SEC W., A DISTANCE OF 207.54 FEET; THENCE (45) S.61 DEG. 20 MIN. 48 SEC W., A DISTANCE OF 23.85 FEET; THENCE (46) N.79 DEG. 55 MIN. 08 SEC W., A DISTANCE OF 20.10 FEET; THENCE (47) N.50 DEG. 43 MIN. 37 SEC W., A DISTANCE OF 52.43 FEET; THENCE (48) N.85 DEG. 37 MIN. 46 SEC W., A DISTANCE OF 80.00 FEET; THENCE (49) S.47 DEG. 58 MIN. 24 SEC W., A DISTANCE OF 58.00 FEET; THENCE (50) S.00 DEG. 38 MIN. 21 SEC W., A DISTANCE OF 46.10 FEET; THENCE (51) S.25 DEG. 29 MIN. 43 SEC W., A DISTANCE OF 47.17 FEET; THENCE (52) S.74 DEG. 02 MIN. 51 SEC W., A DISTANCE OF 57.58 FEET; THENCE (53) S.71 DEG. 32 MIN. 13 SEC W., A DISTANCE OF 20.62 FEET; THENCE (54) N.84 DEG. 29 MIN. 01 SEC W., A DISTANCE OF 50.01 FEET; THENCE (55) S.87 DEG. 51 MIN. 03 SEC W., A DISTANCE OF 70.46 FEET; THENCE (56) S.78 DEG. 15 MIN. 26 SEC W., A DISTANCE OF 46.84 FEET; THENCE (57) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 40.36 FEET; THENCE (58) S.74 DEG. 57 MIN. 33 SEC W., A DISTANCE OF 111.33 FEET; THENCE (59) N.63 DEG. 11 MIN. 37 SEC W., A DISTANCE OF 167.69 FEET; THENCE (60) N.45 DEG. 49 MIN. 26 SEC W., A DISTANCE OF 39.05 FEET; THENCE (61) S.52 DEG. 23 MIN. 00 SEC W., A DISTANCE OF 26.91 FEET; THENCE (62) N.04

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

DEG. 59 MIN. 23 SEC W., A DISTANCE OF 92.23 FEET; THENCE (63) N.07 DEG. 43 MIN. 27 SEC W., A DISTANCE OF 71.59 FEET; THENCE (64) N.19 DEG. 15 MIN. 01 SEC E., A DISTANCE OF 214.18 FEET; THENCE (65) N.07 DEG. 53 MIN. 39 SEC W., A DISTANCE OF 23.54 FEET; THENCE (66) N.35 DEG. 26 MIN. 06 SEC W., A DISTANCE OF 31.24 FEET; THENCE (67) N.63 DEG. 49 MIN. 41 SEC W., A DISTANCE OF 16.16 FEET; THENCE (68) N.81 DEG. 48 MIN. 55 SEC W., A DISTANCE OF 75.17 FEET; THENCE (69) S.86 DEG. 24 MIN. 03 SEC W., A DISTANCE OF 50.49 FEET; THENCE (70) N.04 DEG. 22 MIN. 14 SEC E., A DISTANCE OF 34.00 FEET; TO THE TRUE POINT OF BEGINNING FOR THIS DESCRIPTION.

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 3.1(a) DELIVERY PERIOD AND MONTHLY CAPACITY PAYMENT

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 3.1(b) VARIABLE O&M CHARGE Generating Unit Name:

Kern River Cogeneration Company Unit 1

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Generating Unit Name:

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

Kern River Cogeneration Company Unit 3

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

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Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 3.1(c) START-UP CHARGE AND CAPACITY AND ANCILLARY SERVICES OPERATING RESTRICTIONS Generating Unit Name:

Kern River Cogeneration Company Unit 1

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

0.00

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Generating Unit Name:

Kern River Cogeneration Company Unit 3

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

0.00

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 5.3 HEAT RATE A. Configuration 1 Information Minimum Generation Capacity (MW):

Maximum Generation Capacity (MW):

70.00

Heat Rate @ Pmax

78.00

12.200

Heat Rate @ Pmin

12.500

Increment (MW):

B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.500

0.00

0.00

0.00

0.00

71.00

12.440

0.00

0.00

0.00

0.00

72.00

12.380

0.00

0.00

0.00

0.00

73.00

12.320

0.00

0.00

0.00

0.00

74.00

12.260

0.00

0.00

0.00

0.00

75.00

12.200

0.00

0.00

0.00

0.00

76.00

12.200

0.00

0.00

0.00

0.00

77.00

12.200

0.00

0.00

0.00

0.00

78.00

12.200

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Generating Unit Name:

Kern River Cogeneration Company Unit 3

A. Configuration 1 Information Minimum Generation Capacity (MW):

Maximum Generation Capacity (MW):

70.00

Heat Rate @ Pmax

80.00

12.200

Heat Rate @ Pmin

12.500

Increment (MW):

B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.500

0.00

0.00

0.00

0.00

71.00

12.440

0.00

0.00

0.00

0.00

72.00

12.380

0.00

0.00

0.00

0.00

73.00

12.320

0.00

0.00

0.00

0.00

74.00

12.260

0.00

0.00

0.00

0.00

75.00

12.200

0.00

0.00

0.00

0.00

76.00

12.200

0.00

0.00

0.00

0.00

77.00

12.200

0.00

0.00

0.00

0.00

78.00

12.200

0.00

0.00

0.00

0.00

79.00

12.200

0.00

0.00

0.00

0.00

80.00

12.200

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

0.00

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.1 AVAILABILITY NOTICE Operating Day: Station:

Issued By:

Generating Unit:

Issued At:

Generating Unit 100% Available No Restrictions: Hour Ending

Minimum Output (MW) (non AGC)

Available Capacity

AGC Available

AGC Min Limit

AGC Max Limit

(MW)

YES/NO

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

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Comments

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APPENDIX 9.2(a) DISPATCH NOTICE Operating Day: Station:

Issued By:

Generating Unit:

Hour Ending

Issued At:

Scheduled Energy

AGC Scheduled

Regulation Up

Regulation Down

Spinning Reserve

(MW)

YES/NO

(MW)

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

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NonSpinning Reserves (MW)

Comments

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.2(b) START-UP NOTICE Date: Station:

Issued By:

Generating Unit:

Issued At:

Date and Time Fire established in Applicable Generating Unit Date and Time Applicable Generating Unit Synchronized Date and Time Applicable Generating Unit Released for Dispatch Type of Start-Up (Hot, Warm, Cold) Fuel Consumed During Start-Up

(MMBtu)

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.2(d) DAILY OPERATING REPORT Daily Operating Reports submitted under this Confirmation should be provided in Excel. For: MM/DD/YY Plant Status at 0600 Generating Unit Name

Replicate for each Generating Unit

Current Availability (MW) Current Operating Level (MW) Current Restrictions (MW)

Prior Day Operating Level (HE)

Hourly Operating Level (Integrated)

Hourly Availability (Integrated)

Generating Unit on AS Control (Y/N)

Nature of Outage

Course of Action to Repair

Outage Date / Return Date

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00 Total Prior Day Significant Events:

Outages (Name of Equipment)

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APPENDIX 9.2(e) COMMUNICATION PROTOCOLS Communication Protocols These Communication Protocols are subject to change and shall be modified as evolving market conditions and rules may require. 1. Contacts and Authorized Representatives The “Contact Information” tables set forth those contact functions, phone/fax numbers and e-mail information by which each Party elects to be contacted by the other. Notification provided under this Confirmation shall be made to the applicable point of contact as set forth in the Contact Information Table. A Party may update its Contact Information by providing notice to the other Party. 2. Communication Protocols: General 2.1 Intra-day Communication: All communications and notices between the Parties that occur intra-day and intra-hour for the applicable Operating Day including those regarding emergencies, Dispatch Notices, Availability Notices, and notices to avoid imbalance penalties, uninstructed deviation charges/credits or any other CAISO charges shall be provided electronically or telephonically as SCE directs to the applicable Party. If to Seller, such notices and communications shall be provided to the following contact, in order of priority, (1) ___________Dispatch Desk/Control Room, (2) ___________Plant Manager, (3) ___________Executive Director. If to SCE, such notices and communications shall be provided to the following contact, in order of priority, Real Time and Natural Gas Scheduling. Each Party shall confirm all Intra-day Communication either electronically or via telephone as soon as practicable. 2.2 Communication Failure: In the event of a failure of the primary communication link between Seller and SCE, both Parties will try all available means to communicate, including cell phones or additional communication devices as installed. 2.3 System Emergency: SCE and Seller shall communicate as soon as possible all changes to the schedule requested by the CAISO as a result of a system emergency. 2.4 Confidentiality: Confidential communications between the Parties in discharging their rights and obligations under the Confirmation and these Communication Protocols will be subject to the applicable restrictions set forth in the Confirmation. 2.5 Staffing: The Parties will have available twenty-four (24) hours a day, seven (7) days a week, personnel available to communicate regarding the implementation of these Communication Protocols.

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Contact Information Table Contacts and Authorized Representatives for SCE Outlined below is the contact and communication information for the relevant contact groups. This list may be amended by SCE with timely notice to Seller. Primary Phone

Contact

Secondary Phone

Day-Ahead Trading

626-307-4487

Day-Ahead Scheduling

626-307-4425

Gas Trading Gas Scheduling

Real Time / MSG Transition Notifications Real Time – Backup Operations Center (not staffed, emergency only) Settlements – Power & Gas

Fax

Email

626-302-3409

[email protected]

626-307-4420

626-302-3409

[email protected]

626-307-4480

626-302-4410*

626-302-3410

[email protected]

626-307-4479

626-302-4410*

626-302-3410

[email protected]

626-307-4410

Cell: 818-424-4575 Sat. Phone: 877-2482129 GOC Fly Away: 877220-9509 (only active in emergencies)

626-302-3409

[email protected] [email protected]

626-307-4410

Cell: 949-466-9909 Sat. Phone: 877-8065625

949-206-7840

[email protected] [email protected]

626-302-3277

626-302-3378

626-302-3276

[email protected]

[insert CM phone here]

626-302-8168

[insert CM email here]ESMpowercontractadmin @sce.com

Contract Administration

626-302-3216

Outage Scheduling / RA Substitution

626-302-3400

[email protected]

Availability Notices

626-302-3400

[email protected]

*Contact the Real Time Generation Desk if after hours; RT will contact the on-call Gas Trader/Scheduler

Contacts and Authorized Representatives for Seller Outlined below is the contact and communication information for the relevant Seller employees. This list may be amended by Seller with timely notice to SCE. Desk

Contact

Direct Phone

Secondary Phones

Dispatch Desk (Day-Ahead) Dispatch Desk (Real Time) Outage Desk Plant Manager

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Fax

Email

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Contract Administration Settlements Operations Manager Operations Supervisor

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APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST [For Natural Gas Fired Boiler Generating Units] This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the procedures described in PTC 46. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). B. Test Parameters. The following Generating Unit Test parameters will be measured and recorded simultaneously at no greater than fifteen (15) minute intervals (except for fuel samples): (1) (2) (3) (4) (5) (6) (7)

instantaneous ambient inlet air relative humidity (in %) within 50 feet of the Generating Unit; instantaneous ambient inlet air temperature (in °F) within 50 feet of the Generating Unit; net Plant output measured at the Energy Delivery Point (in MW); continuous emissions monitoring system (CEMS) data required per air permit; main steam temperature (in °F); main steam pressures (in psig); and fuel flow at the natural gas meter (SCFH).

Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a qualified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters to be defined in the Final Test Plan (Part III,A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time (prior to commencing the four hour test); operated for at least four (4) hours at PMax; and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1.

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SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Capacity Test. Each unit will demonstrate its maximum capacity, PMax, with the following operating parameters. SELLER SHALL INSERT TABLE OF OPERATING TEMPERATURES AND PRESSURES FOR THE UNITS HERE THAT ARE PERTINENT TO THE GENERATING UNITS. In a multiple unit plant, each unit will be isolated from the other unit and provide its own auxiliary power and auxiliary steam requirements during the testing period. E. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized, and brought to PMax using normal start procedures and then operated continuously at PMax for as long as it is necessary, but in no case for no less than one (1) hour, for all measured parameters to achieve stable, normal conditions. During the course of any Test, all measured parameters will not exceed the following tolerances: Generating Unit Performance Maximum Permissible Deviations Variable

Deviation

Power Output (electrical)

±2%

Power Factor

±2%

Fuel (Natural Gas) Heating Value

±2%

Fuel Flow

± 2%

Steam Turbine Variables Main Steam Pressure Main and Reheat Steam Temperatures Feed Water Temperature Leaving Final Heater Exhaust Back Pressure

SELLER TO PROVIDE VALUES FOR EACH UNIT

F. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in PART III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the manufacturer for operation at PMax subject to any Operating Restrictions. G. Test Conditions. At all times during a Test, the Generating Unit shall not be subject to abnormal operating conditions such as: (i) unstable load conditions; (ii) equipment, operating or regulatory restrictions or (iii) changes in the Generating Unit’s electrical output other than those fluctuations arising from normal fuel control capability. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with PART II. K. below.

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H. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. I. Air Emissions. The Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) - Rule 2000 (c)(18) CEMS, is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. J. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Ambient Temperature

°F (Dry Bulb)

Ambient Relative Humidity

%

Measured Net Power Output

MW

Power Factor Generating Unit Emissions

Actual and permit levels

Fuel Higher Heating Value

BTU/Cubic ft.

Note: If fuel analysis is not available by the 4th day after the Test is completed, Seller shall provide it when available or no more than ten (10) Business Days after completion of the Test. K. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with PART II. J. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf, SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives at Seller’s expense.

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L. Final Report. At the later of (i) completion of fuel testing or (ii) within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 46. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3.5 of PTC 46; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. M. Operating Personnel. During any Test, regular site operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. N. SCE Representative. SCE shall be entitled to have at least three (3) representatives present to witness each Test. PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in PART II, above and in accordance with applicable Subsections of PTC 46, Section 3. At least fifteen (15) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and any temporary instrumentation. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, Seller shall calibrate or cause to be calibrated all temporary instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE at least five (5) Business Days prior to the Test.

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Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) for each day unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling a Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1 of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test.

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APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST [For a Simple Cycle Generating Unit] This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the relevant provisions of PTC 22. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). Site Specific Reference Conditions (provided by Seller) Turbine Compressor Inlet Air (“Inlet Air”) Temperature (in °F)

38

Inlet Air Relative Humidity (in %)

25

Barometric Pressure (inches Hg)

28.5

For each Test set forth in this Appendix, the measured test data will be corrected to the Site Specific Reference Conditions using established correction factors. The corrected test data will then be compared to the Test Parameters. B. Parameters. During any Test, at a minimum, the following parameters will be measured and recorded simultaneously for the Generating Unit at no greater than fifteen (15) minute intervals (except for fuel samples): 1) 2) 3) 4) 5) 6) 7) 8)

instantaneous Inlet Air relative humidity (%) with instruments installed in the inlet filter house; instantaneous ambient barometric pressure (inches Hg) with transmitters located near the horizontal centerline of the Generating Unit; instantaneous Inlet Air temperature (°F) with four (4) remote telemetry devices installed in an array inside the filter house; instantaneous site ambient temperature (°F); fuel flow at the Generating Unit natural gas meter (SCFH); net plant output as measured at the Energy Delivery Point (MW); heat rate (BTU/kWh) @ PMax (for testing purposes only) continuous emissions monitoring system (CEMS) data required per air permit.

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Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a qualified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters which will be defined in the Final Test Plan (Part III, A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time prior to commencing the four (4) hour test; operated for at least four (4) hours at PMaxan output, when corrected to Site Specific Reference conditions, is equal to PMax (“Full Load”); and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1. SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized and brought to PMaxFull Load using normal start procedures and then operated continuously at PMaxFull Load for as long as it is necessary, but in no case for no less than one (1) hour, for all measured parameters to achieve stable, normal conditions. During the courseany 30-minute period of any Test, all measured parameters will not exceed the values provided in Table 3-3.5 of PTC 22, “Maximum Permissible Standard Deviations of Measurements in Operating Conditions” in addition to the following: Variable Natural Gas Heating Value (Unit Volume) Absolute Inlet Air Pressure (inches H20)

Permissible Deviation ± 1.3% ± 0.33%

E. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in Part III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the equipment manufacturer for operation at PMax. F. Test Conditions. At all times during a PMaxFull Load Test, the Generating Unit shall be operated with any inlet cooling treatment systems on and such unit shall not be subject to abnormal operating conditions such as (i) ambient conditions requiring the inlet cooling system to be turned off in accordance with manufacturer’s specifications; (ii) unstable load conditions; (iii) equipment, operating or regulatory restrictions or (iv) changes in the Generating Unit’s electrical output other than those fluctuations naturally arising from variations in ambient temperature. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with Part II.J. below.

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G. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. H. Air Emissions. Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) Rule 2000 (c)(18) CEMS, is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. I. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Site Ambient Air Temperature Inlet Air Temperature Inlet Air Relative Humidity Barometric Pressure Measured Net Power Output Inlet Air Treatment (Evaporative Cooler, Foggers, or Chiller) Power Factor Steam / Water Injection Generating Unit Emissions Fuel Heating Value (HHV)

°F (Dry Bulb) °F (Dry Bulb) % inches Hg MW on/off on/off (if applicable) Actual and permit levels BTU/Cubic ft

Note: If fuel analysis is not available by the fourth day after the Test is completed, Seller shall provide it on the earlier of when available or ten (10) Business Days after the Test is completed. J. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with Part II.I. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf,

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SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives, at Seller’s expense. K. Final Report. Within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 22. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8) (9)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3-5 of PTC 22; demonstration of the correction of the measured test data to the Site Specific Reference Conditions, with supporting calculations; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. L. Operating Personnel. During any Test, the same operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. M. SCE Representative. SCE shall be entitled to have at least two representatives present to witness each Test. PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in Part II, above and in accordance with applicable Subsections of PTC 22, Section 3. At least ten (10) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and the temporary instrumentation suggested by Seller or deemed necessary by SCE in its sole judgement. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with written notice of the temporary calibrated instrumentation that will be used during the Test. Seller shall calibrate or cause to be calibrated all such instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All

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electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE at least five (5) Business Days prior to the Test. Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. In addition Seller shall provide a temporary data acquisition system to monitor all temporary instruments. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling each Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1(a) of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test. G. Table. If SCE requests, Seller shall create a table relating Contract Capacity (in MW) to Inlet Air temperature, such that the Contract Capacity of the Generating Unit shall be the expected output of the Generating Unit at Test Conditions, and the expected output of the Generating Unit at other Inlet Air temperatures shall relate to Contract Capacity in the same proportion as the points on the manufacturer’s performance curve relate to that curve at Test Conditions. Such table will be provided to SCE as part of the Final Report.

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APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST [For a Combined Cycle Generating Unit] This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the relevant provisions of PTC 22 and PTC 46. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). Site Specific Reference Conditions (provided by Seller) Turbine Compressor Inlet Air (“Inlet Air”) Temperature (in °F) Inlet Air Relative Humidity (%) Barometric Pressure (in Hg) For each Test set forth in this Appendix, the measured test data will be corrected to the Site Specific Reference Conditions using established correction factors. The corrected test data will then be compared to the Test Parameters. B. Parameters. During any Test, at a minimum, the following parameters will be measured and recorded simultaneously for the Generating Unit at no greater than fifteen (15) minute intervals (except for fuel samples): 1) 2) 3) 4) 5) 6) 7) 8) 9) 10)

instantaneous Inlet Air relative humidity (%) with instruments installed in the inlet filter house; instantaneous ambient barometric pressure (inches Hg) with transmitters located near the horizontal centerline of the Generating Unit; instantaneous Inlet Air temperature (°F) with four (4) remote telemetry devices installed in an array inside the filter house; instantaneous site ambient temperature (°F); fuel flow at the Generating Unit natural gas meter (SCFH); net plant output as measured at the Energy Delivery Point (MW); heat rate (BTU/kWh) @ PMax (for testing purposes only); continuous emissions monitoring system (CEMS) data required per air permit; steam turbine main steam temperature (°F); steam turbine main steam pressure (psig).

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Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a quallified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters which will be defined in the Final Test Plan (Part III, A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time prior to commencing the four (4) hour test; operated for at least four (4) hours at PMax; and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1. SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized and brought to PMax using normal start procedures and then operated continuously at PMax for as long as it is necessary, but in no case for no less than one (1) hour. During the course of any Test, all measured parameters will not exceed the values provided in Table 3-3.5 of PTC 22, ““Maximum Permissible Standard Deviations of Measurements in Operating Conditions” in addition to the following: Variable

Permissible Deviation

Natural Gas Heating Value (Unit Volume)

± 1.3%

Absolute Inlet Air Pressure

± 0.33%

Steam Turbine Main Steam Pressure

± 3%

HRSG Main & Reheat Steam Temperature

± 30 °F

Steam Turbine Exhaust Pressure

± 0.05 PSIA or ± 2.50% - whichever is larger

E. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in Part III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the equipment manufacturer for operation at PMax. F. Test Conditions. At all times during a PMax Test, the Generating Unit shall be operated with any inlet cooling treatment systems on and such unit shall not be subject to abnormal operating conditions such as (i) ambient conditions requiring the inlet cooling system to be turned off in accordance with the equipment manufacturer’s specifications; (ii) unstable load conditions; (iii) equipment, operating or regulatory restrictions or (iv) changes in the Generating Unit’s electrical output other than those fluctuations naturally arising from variations in ambient

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temperature. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with Part II.J. below. G. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. H. Air Emissions. Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) - Rule 2000 (c)(18) CEMS is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. I. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Site Ambient Air Temperature

°F (Dry Bulb)

Inlet Air Temperature

°F (Dry Bulb)

Inlet Air Relative Humidity

%

Barometric Pressure

Inches Hg

Measured Net Power Output

MW

Inlet Air Treatment (Evaporative Cooer, Foggers, or Chiller)

on/off

Power Factor Steam / Water Injection

on/off (if applicable)

Power Augmentation

on/off (if applicable)

Generating Unit Emissions

Actual and permit levels

Fuel Heating Value (HHV)

BTU/Cubic ft

Duct Burner Fuel Flow

BTU/Hr

Note: if fuel analysis is not available by the fourth day after the Test is completed, Seller shall provide it on the earlier of when available or ten (10) Business Days after the Test is completed.

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J. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with Part II.I. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf, SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives, at Seller’s expense. K. Final Report. Within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 46. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8) (9)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3.5 of PTC 46; demonstration of the correction of the measured test data to the Site Specific Reference Conditions, with supporting calculations; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. L. Operating Personnel. During any Test, the same operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. M. SCE Representative. SCE shall be entitled to have at least two representatives present to witness each Test. PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in Part II., above and in accordance with applicable Subsections of PTC 46, Section 3. At least ten (10) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed

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Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and the temporary instrumentation suggested by Seller or deemed necessary by SCE in its sole judgement. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with written notice of the temporary calibrated instrumentation that will be used during the Test. Seller shall calibrate or cause to be calibrated all such instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE at least five (5) Business Days prior to the Test. Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. In addition Seller shall provide a temporary data acquisition system to monitor all temporary instruments. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling each Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1 of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test. G. Table. If SCE requests, Seller shall create a table relating Contract Capacity (in MW) to Inlet Air temperature, such that the Contract Capacity of the Generating Unit shall be the expected output of the Generating Unit at Test Conditions, and the expected output of the Generating Unit at other Inlet Air temperatures shall relate to Contract Capacity in the same proportion as the points on the manufacturer’s performance curve relate to that curve at Test Conditions. Such table will be provided to SCE as part of the Final Report.

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APPENDIX 11.1 PLANNED OUTAGE REPORT

Planned Outage Reports submitted under this Confirmation should be provided in Excel.

DATE OF UPDATE RESOURCE NAME Replicate for each Generating Unit

Planned Outages Start Date

HE

End Date

88

HE

MW Available

Cause

Emergency Time of Return

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 12.3 DELIVERY OF DATA The following is a list of real time generic data points to be electronically exchanged between Seller and SCE. SCE may add items to or delete items from this list at its reasonable discretion prior to the beginning of the Delivery Period. Additional meetings will be scheduled to clarify and finalize points list prior to configuration tasks.

Point description: From Generator DNP - XXX UNIT# Breaker DNP - XXX UNIT# AGC CTRL AVAILABILITY ONOFF DNP - XXX UNIT# ISO RIG Lost Communication DNP - XXX UNIT# High Operating Limit DNP - XXX UNIT# Low Operating Limit DNP - XXX UNIT# ISO AGC set point DNP - XXX UNIT# Net MW (POD) DNP - XXX UNIT# Capacity DNP - XXX UNIT# Max Sustained Ramp Rate

From GMS Control Related DNP - XXX UNIT# AGC model - ISO AGC DNP - XXX UNIT# AGC model – SFM DNP - XXX UNIT# AGC model – MAN DNP - XXX UNIT# AGC model – OFF DNP - XXX UNIT# Dispatch Energy Schedule "GO TO" DNP - XXX UNIT# Reg Up Awarded MW DNP - XXX UNIT# Reg Down Awarded MW DNP - XXX UNIT# Spin Awarded MW DNP - XXX UNIT# Non-Spin Awarded MW DNP - XXX UNIT# Set Point (MW) DNP - XXX UNIT# Ramp Rate (MW/M)

From GMS Schedules Related DNP - SCH HA Today XXX UNIT# HE01 DNP - SCH HA Today XXX UNIT# HE02 DNP - SCH HA Today XXX UNIT# HE03 DNP - SCH HA Today XXX UNIT# HE04 DNP - SCH HA Today XXX UNIT# HE05 DNP - SCH HA Today XXX UNIT# HE06 DNP - SCH HA Today XXX UNIT# HE07 DNP - SCH HA Today XXX UNIT# HE08 DNP - SCH HA Today XXX UNIT# HE09 DNP - SCH HA Today XXX UNIT# HE10 DNP - SCH HA Today XXX UNIT# HE11 DNP - SCH HA Today XXX UNIT# HE12 DNP - SCH HA Today XXX UNIT# HE13

89

From GMS Schedules Related (cont.) DNP - SCH HA Today XXX UNIT# HE14 DNP - SCH HA Today XXX UNIT# HE15 DNP - SCH HA Today XXX UNIT# HE16 DNP - SCH HA Today XXX UNIT# HE17 DNP - SCH HA Today XXX UNIT# HE18 DNP - SCH HA Today XXX UNIT# HE19 DNP - SCH HA Today XXX UNIT# HE20 DNP - SCH HA Today XXX UNIT# HE21 DNP - SCH HA Today XXX UNIT# HE22 DNP - SCH HA Today XXX UNIT# HE23 DNP - SCH HA Today XXX UNIT# HE24 DNP - SCH HA Today XXX UNIT# HE25 DNP - SCH HA Tomorrow XXX UNIT# HE01 DNP - SCH HA Tomorrow XXX UNIT# HE02 DNP - SCH HA Tomorrow XXX UNIT# HE03 DNP - SCH HA Tomorrow XXX UNIT# HE04 DNP - SCH HA Tomorrow XXX UNIT# HE05 DNP - SCH HA Tomorrow XXX UNIT# HE06 DNP - SCH HA Tomorrow XXX UNIT# HE07 DNP - SCH HA Tomorrow XXX UNIT# HE08 DNP - SCH HA Tomorrow XXX UNIT# HE09 DNP - SCH HA Tomorrow XXX UNIT# HE10 DNP - SCH HA Tomorrow XXX UNIT# HE11 DNP - SCH HA Tomorrow XXX UNIT# HE12 DNP - SCH HA Tomorrow XXX UNIT# HE13 DNP - SCH HA Tomorrow XXX UNIT# HE14 DNP - SCH HA Tomorrow XXX UNIT# HE15 DNP - SCH HA Tomorrow XXX UNIT# HE16 DNP - SCH HA Tomorrow XXX UNIT# HE17 DNP - SCH HA Tomorrow XXX UNIT# HE18 DNP - SCH HA Tomorrow XXX UNIT# HE19 DNP - SCH HA Tomorrow XXX UNIT# HE20 DNP - SCH HA Tomorrow XXX UNIT# HE21 DNP - SCH HA Tomorrow XXX UNIT# HE22 DNP - SCH HA Tomorrow XXX UNIT# HE23 DNP - SCH HA Tomorrow XXX UNIT# HE24 DNP - SCH HA Tomorrow XXX UNIT# HE25

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 13.3(b) HISTORICAL OUTAGE REPORT [To be provided by Seller]APPENDIX 13.3(c) DISCLOSURE SCHEDULE [To be provided by Seller] None

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APPENDIX 13.3(d)

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HISTORICAL OUTAGE REPORT KERN RIVER COGENERATION COMPANY GENERATING UNIT #1 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1 1

Available Time Thu 01Jan09 00:00 Sat 03Jan09 15:09 Sun 04Jan09 06:20 Sat 14Feb09 13:54 Tue 10Mar09 17:37 Sat 04Apr09 08:00 Sat 09May09 20:00 Sat 10Oct09 13:58 Tue 13Oct09 21:31 Fri 16Oct09 02:02 Fri 16Oct09 22:26 Sat 21Nov09 13:58 Sat 16Jan10 15:01 Mon 08Mar10 07:54 Sat 24Apr10 08:41 Mon 01Nov10 11:41 Mon 01Nov10 21:26 Tue 02Nov10 12:21 Mon 08Nov10 07:00 Thu 11Nov10 10:44 Sat 01Jan11 14:21 Wed 02Feb11 10:27 Wed 09Mar11 12:51 Mon 07Nov11 07:48 Mon 07Nov11 08:10 Mon 07Nov11 09:10 Sat 03Dec11 11:32 Sun 04Dec11 02:52 Sun 04Dec11 09:17 Mon 05Dec11 07:46 Tue 06Dec11 08:45 Wed 07Dec11 09:57 Thu 08Dec11 09:24 Thu 08Dec11 13:03 Fri 09Dec11 10:22 Thu 15Dec11 09:18 Tue 20Dec11 10:25 Fri 23Dec11 09:45 Sat 24Dec11 09:45 Sun 25Dec11 14:36 Mon 26Dec11 10:14 Tue 27Dec11 10:22 Wed 28Dec11 10:21 Thu 29Dec11 09:17 Fri 30Dec11 10:19 Sat 31Dec11 10:18 Sun 01Jan12 10:18 Mon 09Jan12 08:32 Fri 13Jan12 12:47 Tue 17Jan12 09:19 Thu 19Jan12 10:17 Sun 26Feb12 15:38

UnAvailable Time Available Hours Reason UnAvailable Sat 03Jan09 07:21 55.4 Crankwash Sat 03Jan09 16:50 1.7 Steam Line gasked replaced Sat 14Feb09 07:11 984.8 Crankwash Tue 10Mar09 15:59 578.1 Primary Reignition - Reset and Restarted Unit Sun 15Mar09 21:05 123.5 Generator Maintenance Sat 09May09 00:00 832.0 DCS Upgraded to Ovation Control System Fri 09Oct09 21:02 3673.0 Generator Field Voltage PTs and Transducers maintenance Tue 13Oct09 20:55 79.0 Trip on Loss of Excitation Fri 16Oct09 01:30 52.0 Trip on Loss of Excitation Fri 16Oct09 21:03 19.0 Replaced Inner Loop Regulator Card Sat 21Nov09 07:11 848.8 Crankwash Sat 16Jan10 07:12 1337.2 Crankwash Mon 08Mar10 00:13 1209.2 Crankwash Sun 18Apr10 21:09 997.2 Combustion Inspection - UnAvailable Mon 01Nov10 09:54 4585.2 Flashbacks induced Emissions Exceedence - Reset Mon 01Nov10 12:32 0.8 Flashbacks induced Emissions Exceedence - Washed Unit Mon 01Nov10 21:52 0.4 Unstable combustion system - failure to reignite primaries trip Tue 02Nov10 12:51 0.5 Unstable combustion system troubleshooting Mon 08Nov10 07:00 0.0 Combustion Inspection Sat 01Jan11 12:32 1225.8 Numerous Flashbacks - Reset and Restarted Wed 02Feb11 09:54 763.5 Flashbacks and High Emissions Wed 09Mar11 10:04 839.6 Cleaned dirty flame detectors - Pilot valve maintenance Mon 07Nov11 07:43 5826.9 Generator excitation system troubleshooting and adjustment Mon 07Nov11 07:48 0.0 Generator excitation system troubleshooting and adjustment Mon 07Nov11 08:10 0.0 Generator excitation system troubleshooting and adjustment Sat 03Dec11 08:02 622.9 Shutdown to avoid emissions exceedence Sun 04Dec11 00:05 12.5 Shutdown to avoid emissions exceedence Sun 04Dec11 03:52 1.0 Shutdown to avoid emissions exceedence Sun 04Dec11 21:46 12.5 Failed to reignite after flashback - cleaned flame detectors Tue 06Dec11 05:42 21.9 Shutdown to avoid emissions exceedence Tue 06Dec11 22:04 13.3 Shutdown to avoid emissions exceedence Thu 08Dec11 05:58 20.0 Shutdown to avoid emissions exceedence Thu 08Dec11 11:15 1.8 Shutdown to avoid emissions exceedence Thu 08Dec11 20:12 7.2 Shutdown to avoid emissions exceedence Thu 15Dec11 08:05 141.7 Shutdown to avoid emissions exceedence Tue 20Dec11 08:08 118.8 Shutdown to avoid emissions exceedence Fri 23Dec11 08:03 69.6 Shutdown to avoid emissions exceedence Sat 24Dec11 05:03 19.3 Shutdown to avoid emissions exceedence Sun 25Dec11 13:03 27.3 Shutdown to avoid emissions exceedence Mon 26Dec11 03:04 12.5 Shutdown to avoid emissions exceedence Tue 27Dec11 01:04 14.8 Shutdown to avoid emissions exceedence Tue 27Dec11 22:56 12.6 Shutdown to avoid emissions exceedence Thu 29Dec11 06:10 19.8 Shutdown to avoid emissions exceedence Fri 30Dec11 01:02 15.8 Shutdown to avoid emissions exceedence Sat 31Dec11 02:57 16.6 Shutdown to avoid emissions exceedence Sun 01Jan12 05:01 18.7 Unit Tripped - Flashback - Failed to Re-ignite Primaries Mon 09Jan12 03:54 185.6 Shutdown to avoid emissions exceedence Wed 11Jan12 00:08 39.6 Bleed Heat System Installed Tue 17Jan12 03:49 87.0 Shutdown to avoid emissions exceedence Thu 19Jan12 04:46 43.5 Shutdown to avoid emissions exceedence Sun 26Feb12 03:50 905.5 Voltz/Hertz Card Failure - Excitation System PT repair Tue 01May12 00:00 1544.4 End of Data Set Total Available Hours 28,040.0 Total Hours 29,184.0 % Available 96.08%

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KERN RIVER COGENERATION COMPANY GENERATING UNIT #3 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3

Available Time Thu 01Jan09 00:00 Sat 09May09 19:56 Tue 26May09 12:30 Fri 05Jun09 10:51 Sat 13Jun09 06:38 Sat 25Jul09 08:01 Sat 05Sep09 15:01 Tue 22Dec09 00:14 Sat 17Apr10 07:56 Mon 10May10 04:40 Tue 11May10 08:01 Mon 24May10 08:37 Wed 21Jul10 00:48 Sun 29Aug10 14:51 Tue 21Sep10 12:17 Thu 03Feb11 17:18 Thu 03Feb11 22:00 Fri 04Feb11 16:13 Tue 03May11 10:46 Mon 09May11 07:45 Tue 10May11 08:22 Sun 15May11 12:46 Mon 16May11 12:44 Thu 26May11 09:22 Sun 29May11 08:36 Mon 30May11 09:48 Tue 31May11 10:51 Wed 01Jun11 00:00 Sat 04Jun11 07:49 Mon 06Jun11 01:18 Mon 06Jun11 10:58 Thu 30Jun11 11:54 Tue 12Jul11 08:58 Wed 13Jul11 08:56 Thu 14Jul11 08:51 Fri 15Jul11 08:51 Sat 16Jul11 08:50 Sun 17Jul11 07:45 Mon 18Jul11 07:45 Tue 19Jul11 07:45 Thu 04Aug11 09:48 Tue 16Aug11 07:51 Wed 17Aug11 10:45 Sat 08Oct11 06:01 Mon 24Oct11 08:13 Mon 24Oct11 09:24 Wed 02Nov11 10:28 Wed 02Nov11 13:55 Fri 04Nov11 15:18 Fri 04Nov11 21:44 Sat 05Nov11 13:14 Sun 06Nov11 09:18 Mon 07Nov11 09:10 Tue 08Nov11 09:00 Wed 09Nov11 08:00 Thu 10Nov11 08:00 Fri 11Nov11 07:00 Sat 12Nov11 08:00 Sun 13Nov11 10:00 Mon 14Nov11 08:00 Tue 15Nov11 09:00

UnAvailable Time Sat 09May09 00:11 Tue 26May09 11:41 Fri 05Jun09 05:54 Sat 13Jun09 00:13 Sat 25Jul09 00:12 Sat 05Sep09 07:11 Mon 07Dec09 17:10 Mon 12Apr10 05:00 Mon 10May10 02:17 Tue 11May10 02:27 Sat 22May10 09:57 Tue 20Jul10 23:15 Sun 29Aug10 06:55 Tue 21Sep10 11:38 Thu 03Feb11 16:38 Thu 03Feb11 20:00 Thu 03Feb11 22:00 Tue 03May11 06:11 Sat 07May11 00:13 Tue 10May11 06:56 Sun 15May11 06:36 Sun 15May11 21:58 Mon 16May11 19:55 Thu 26May11 18:01 Mon 30May11 04:03 Tue 31May11 04:00 Tue 31May11 21:06 Wed 01Jun11 00:00 Sun 05Jun11 22:58 Mon 06Jun11 01:52 Wed 29Jun11 23:27 Tue 12Jul11 03:46 Wed 13Jul11 04:04 Thu 14Jul11 02:05 Fri 15Jul11 00:47 Sat 16Jul11 00:04 Sat 16Jul11 23:57 Mon 18Jul11 03:00 Tue 19Jul11 05:15 Thu 04Aug11 03:11 Sun 14Aug11 21:03 Tue 16Aug11 15:50 Sat 08Oct11 03:32 Fri 14Oct11 21:07 Mon 24Oct11 08:28 Wed 02Nov11 09:53 Wed 02Nov11 13:18 Fri 04Nov11 13:01 Fri 04Nov11 18:03 Fri 04Nov11 22:43 Sat 05Nov11 21:55 Sun 06Nov11 18:11 Mon 07Nov11 19:00 Tue 08Nov11 22:00 Thu 10Nov11 02:00 Fri 11Nov11 03:00 Sat 12Nov11 03:00 Sat 12Nov11 20:00 Sun 13Nov11 23:00 Mon 14Nov11 20:00 Wed 16Nov11 02:00

Available Hours 3072.2 399.8 233.4 181.4 1001.6 1007.2 2234.2 2668.8 546.3 21.8 265.9 1382.6 942.1 548.8 3244.4 2.7 0.0 2102.0 85.5 23.2 118.2 9.2 7.2 8.7 19.5 18.2 10.3 0.0 39.1 0.6 564.5 279.9 19.1 17.2 15.9 15.2 15.1 19.3 21.5 379.4 251.3 8.0 1240.8 159.1 0.2 216.5 2.8 47.1 2.8 1.0 8.7 8.9 9.8 13.0 18.0 19.0 20.0 12.0 13.0 12.0 17.0

93

Reason UnAvailable DCS Upgraded to Ovation Control System Emissions Exceedence - Cleaned Flame Detectors Emissions Exceedence - Flame Detectors Cleaned Crankwash CRANKWASH Crankwash - Gas Valve Inspection Emissions Exceedence - Combustion Inspection Combustion Inspection - UnAvailable Emissions Exceedence - Reset and Restarted Unit Emissions Exceedence - Cleaned Flame Detectors Emissions Exceedence - Mini CI - Replaced Primary Fuel Nozzles High NOx Emissions shutdown - Adjusted Nox Analyzer Crankwash Unit Tripped unintentionally while breaker testing Loss of Flame - Cleaned flame detectors High Nox and CO Cleaned Flame Detectors and changed Control Constants High NOx - Shutdown to avoid emissions exceedence Mini Combustion Inspection Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Mini CI - Replaced Primary and Secondary Fuel Nozzles Unable to Tune - Replaced Secondary Nozzles Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Mini CI - Replaced Fuel Nozzles and Liners Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Emissions Exceedence - Replaced #8 Secondary Fuel Nozzle Replaced Secondary Fuel Nozzles Emissions Exceedence - Replaced #3 Primary Fuel Nozzle Shutdown to avoid emissions exceedence Extended CI - Replaced 1st stage nozzle Shutdown to install missing secondary fuel nozzle port plug High combustion dynamics - Reset and restarted unit Unit tripped during recalibration of Humidity Transmitter Shut down unit to change combustion control constants Shutdown to avoid emissions exceedence Shutdown to avoid emissions exceedence Unit tripped on Failure to Reignite Primaries Shutdown to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence Unavailabe to avoid emissions exceedence

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Unit 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3 3

Available Time Wed 16Nov11 08:00 Thu 17Nov11 08:00 Fri 18Nov11 08:00 Sat 19Nov11 11:00 Sun 20Nov11 10:00 Mon 21Nov11 10:00 Tue 22Nov11 13:00 Wed 23Nov11 06:49 Fri 25Nov11 08:00 Sat 26Nov11 09:00 Sun 27Nov11 08:00 Mon 28Nov11 08:00 Tue 29Nov11 08:00 Wed 30Nov11 08:00 Thu 01Dec11 10:00 Fri 02Dec11 10:00 Sun 04Dec11 10:00 Mon 05Dec11 10:00 Tue 06Dec11 10:00 Wed 07Dec11 10:00 Thu 08Dec11 09:00 Fri 09Dec11 09:00 Sat 10Dec11 09:00 Sun 11Dec11 10:00 Mon 12Dec11 09:00 Tue 13Dec11 09:00 Wed 14Dec11 09:00 Thu 15Dec11 09:00 Fri 16Dec11 10:00 Sat 17Dec11 10:00 Sun 18Dec11 09:00 Mon 19Dec11 09:00 Tue 13Mar12 16:30 Wed 18Apr12 20:00

UnAvailable Time Available Hours Reason UnAvailable Wed 16Nov11 23:00 15.0 Unavailabe to avoid emissions exceedence Fri 18Nov11 01:00 17.0 Unavailabe to avoid emissions exceedence Fri 18Nov11 23:00 15.0 Unavailabe to avoid emissions exceedence Sat 19Nov11 18:00 7.0 Unavailabe to avoid emissions exceedence Sun 20Nov11 20:00 10.0 Unavailabe to avoid emissions exceedence Mon 21Nov11 21:00 11.0 Unavailabe to avoid emissions exceedence Tue 22Nov11 21:00 8.0 Unavailabe to avoid emissions exceedence Fri 25Nov11 00:00 41.2 Unavailabe to avoid emissions exceedence Fri 25Nov11 22:00 14.0 Unavailabe to avoid emissions exceedence Sat 26Nov11 22:00 13.0 Unavailabe to avoid emissions exceedence Sun 27Nov11 22:00 14.0 Unavailabe to avoid emissions exceedence Mon 28Nov11 21:00 13.0 Unavailabe to avoid emissions exceedence Tue 29Nov11 22:00 14.0 Unavailabe to avoid emissions exceedence Thu 01Dec11 00:00 16.0 Unavailabe to avoid emissions exceedence Thu 01Dec11 19:00 9.0 Unavailabe to avoid emissions exceedence Sat 03Dec11 19:00 33.0 Unavailabe to avoid emissions exceedence Sun 04Dec11 18:00 8.0 Unavailabe to avoid emissions exceedence Mon 05Dec11 18:00 8.0 Unavailabe to avoid emissions exceedence Tue 06Dec11 18:00 8.0 Unavailabe to avoid emissions exceedence Wed 07Dec11 19:00 9.0 Unavailabe to avoid emissions exceedence Thu 08Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Fri 09Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Sat 10Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Sun 11Dec11 20:00 10.0 Unavailabe to avoid emissions exceedence Mon 12Dec11 23:00 14.0 Unavailabe to avoid emissions exceedence Tue 13Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Wed 14Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Thu 15Dec11 20:00 11.0 Unavailabe to avoid emissions exceedence Fri 16Dec11 20:00 10.0 Unavailabe to avoid emissions exceedence Sat 17Dec11 19:00 9.0 Unavailabe to avoid emissions exceedence Sun 18Dec11 19:00 10.0 Unavailabe to avoid emissions exceedence Tue 13Mar12 00:00 2031.0 Replaced Fuel Gas Safties Tue 17Apr12 05:00 828.5 Transformer Maintenance PT and CT Inspection Tue 01May12 00:00 292.0 End of Data Set Total Available Hours 27,171.1 Total Hours 29,184.0 % Available 93.10%

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APPENDIX 1514 SHAPED PRICE CALCULATION 1

Shape Calculation a) “Shape” shall be the ratio, expressed as a percentage, of a Forward Price Assessment of (i) the price of power for a calendar quarter to the price of power for the calendar year that such quarter falls within, or (ii) the price of power for a month to the price of power for the quarter that such month falls within. b) There are four quarterly Shapes (for the first through fourth calendar quarters) and twelve monthly Shapes (for the months of January through December) in every calendar year. 1.

For purposes of determining the applicable quarterly Shape, an annual price is calculated as the simple average of the four quarterly prices within the last available year. For example, the first quarter Shape is calculated using the formula below: ShapeQ1 = PQ1 / Average (PQ1 + PQ2 + PQ3 + PQ4)

2.

For purposes of determining the applicable monthly Shape, a quarterly price is calculated as the simple average of the three monthly prices within the applicable quarter. For example, the January Shape is calculated using the formula below: ShapeJan = PJan / Average (PJan + PFeb + PMar)

2

Calculation of Shaped Prices “Shaped Price” shall mean, if there is no Forward Price Assessment for the relevant calendar month, the price of power calculated in accordance with the following process. If no monthly price is available for a Forward Price Assessment but a quarterly price is available, then use a monthly Shape to calculate a monthly Shaped Price from a quarterly price using the following formula: PM = PQ × ShapeM Where: PM is the missing monthly power price PQ is the quarterly power price applicable to the relevant calendar month ShapeM is the applicable “Shape” for the missing month If no monthly or quarterly price is available for a Forward Price Assessment but an annual price is available, then use a quarterly Shape to calculate a quarterly Shaped Price from an annual price using the following formula: PQ = PY × ShapeQ Where: PQ is the missing quarterly power price PY is the yearly power price applicable to the applicable calendar quarter ShapeQ is the applicable “Shape” for the missing quarter

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793

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

PARAGRAPH 10 to the COLLATERAL ANNEX to the EEI MASTER POWER PURCHASE AND SALE AGREEMENT Between ____Kern River Cogeneration Company (“Party A”) and Southern California Edison Company (“SCE” or “Party B”) CREDIT ELECTIONS COVER SHEET Paragraph 10. Elections and Variables I.

Collateral Threshold. A.

Party A Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party A shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party A; and provided further that, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party A Collateral Threshold” opposite the Credit Rating for [Party A][Party A’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party A][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing; provided, however, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand. Party A Collateral Threshold $__________ $__________ $__________ $__________ $__________



Credit Rating _______ (or above) _______ _______ _______ Below _______

The amount (“Threshold Amount”) which is the lowest of:

(1) the amount set forth below under the heading “Party A Collateral Threshold” opposite the lower of the Credit Ratings for Party A or, if applicable, Party A’s Guarantor on the relevant date of determination. If Party A or, if applicable, its Guarantor is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party A or, if applicable, its Guarantor is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party A or, if applicable,

11

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

its Guarantor does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) 80% of the amount of the guaranty agreement, as amended from time to time, provided by Party A’s Guarantor, if any, for the benefit of Party B; or (3) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing: Party A Collateral Threshold (in thousands of US Dollars) $[To be negotiated]25,000 $[To be negotiated]20,000 $[To be negotiated]20,000 $[To be negotiated]17,000 $[To be negotiated]9,000 $[To be negotiated]6,250 $[To be negotiated]3,750 $ 0 (zero)

B.

Moody’s Credit Rating

S&P Credit Rating

Fitch Credit Rating

Aa3 or above

AA- or above

AA- or above

A1

A+

A+

A2

A

A

A3

A-

A-

Baa1 Baa2 Baa3 Ba1 or below

BBB+ BBB BBBBB+ or below

BBB+ BBB BBBBB+ or below



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party A’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Party B Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party B shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party B; and provided further that, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party B Collateral Threshold” opposite the Credit Rating for [Party B][Party B’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party B][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing; provided, however, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand:

22

Paragraph 10 to the Collateral Annex SCE v.09.17.2008



Party B Collateral Threshold

_____Credit Rating

$__________ $__________ $__________ $__________ $__________

_______ (or above) _______ _______ _______ Below _______

The amount (the “Threshold Amount”) which is the lower of:

(1) the amount set forth below under the heading “Party B Collateral Threshold” opposite the lower of the Credit Ratings for Party B on the relevant date of determination. If Party B is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party B is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party B does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing: Party B Moody’s S&P Fitch Collateral Threshold Credit Rating Credit Rating Credit Rating (in thousands of US Dollars) $[To be Aa3 or above AA- or above AA- or above negotiated]25,000 $[To be A1 A+ A+ negotiated]20,000 $[To be A2 A A negotiated]20,000 $[To be A3 AAnegotiated]17,000 $[To be negotiated]9,000 Baa1 BBB+ BBB+ $[To be negotiated]6,250 Baa2 BBB BBB $[To be negotiated]3,750 Baa3 BBBBBB$ 0 (zero) Ba1 or below BB+ or below BB+ or below

II.



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party B’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Eligible Collateral and Valuation Percentage. The following items will qualify as "Eligible Collateral" for the Party specified: Party A

Party B

Valuation Percentage

(A)

Cash

[X]

[X]

100%

(B)

Letters of Credit

[X]

[X]

100% unless either (i) a Letter of Credit Default shall have occurred and be continuing with respect to such Letter of Credit, or (ii) twenty (20) or fewer Business Days remain prior to the expiration of such Letter of Credit, in which cases the Valuation Percentage shall be zero (0%).

33

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

(C) III.

Other

[ ]

[ ]

________%

Independent Amount. A.

Party A Independent Amount. 

Party A shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount option is selected for Party A, then Party A (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party B (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party A’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex. Party A shall have a Full Floating Independent Amount of (i) the amount specified in a Transaction or Confirmation, if any; and (ii) if Party A’s Credit Rating is lower than BBBby S&P, Baa3 by Moody’s, or BBB- by Fitch, the amount equal to ten percent (10%) of the market value of all outstanding Transactions (except those for which an alternative Independent Amount is specified in the Confirmation), adjusted by the netting of the market value of purchases with the market value of sales within the same billing cycles. If the Full Floating Independent Amount option is selected for Party A, then for purposes of calculating the Collateral Requirements pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party A shall be added to the Exposure Amount for Party B and subtracted from the Exposure Amount for Party A. [This option is applicable if Party A does not have investment grade Credit Ratings.] Party A shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party A, then Party A will be required to Transfer or cause to be Transferred to Party B Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party A otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced so long as Party A has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex. Not Applicable. [This option is applicable if Party A or its Guarantor has investment grade Credit Ratings.]

B.

Party B Independent Amount. 

Party B shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount Option is selected for Party B, then Party B (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party A (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any

44

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party B’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex. Party B shall have a Full Floating Independent Amount of $______________. If the Full Floating Independent Amount Option is selected for Party B then for purposes of calculating Party B’s Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party B shall be added by Party A to its Exposure Amount for purposes of determining Net Exposure pursuant to Paragraph 3(a) of the Transition Collateral Annex. 

Party B shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party B, then Party B will be required to Transfer or cause to be Transferred to Party A Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party B otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced for so long as Party B has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex. Not Applicable.

IV.

V.

VI.

Minimum Transfer Amount. A.

Party A Minimum Transfer Amount:

$0.00

B.

Party B Minimum Transfer Amount:

$0.00

Rounding Amount. A.

Party A Rounding Amount:

$250,000.00

B.

Party B Rounding Amount:

$250,000.00

Administration of Cash Collateral. A.

Party A Eligibility to Hold Cash. 

Party A shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B.



Party A shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party A or, if applicable, Party A’s Guarantor has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by

55

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party A or its Guarantor has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or on “Credit Watch” negative or developing by Fitch, then Party A shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party A is entitled to hold Cash, the Interest Rate payable to Party B on Cash shall be as selected below: Party A Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

To the extent that Party A is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B. B.

Party B Eligibility to Hold Cash. 

Party B shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A.



Party B shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party B has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party B has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or “Credit Watch” negative or developing by Fitch, then Party B shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party B is entitled to hold Cash, the Interest Rate payable to Party A on Cash shall be as selected below: Party B Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

66

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

To the extent that Party B is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A. VII.

Notification Time. 10:00 a.m. Pacific Prevailing Time on a Local Business Day.

VIII.

General. With respect to the Collateral Threshold, Independent Amount, Minimum Transfer Amount and Rounding Amount, if no selection is made in this Cover Sheet with respect to a Party, then the applicable amount in each case for such Party shall be zero (0). In addition, with respect to the “Administration of Cash Collateral” section of this Paragraph 10, if no selection is made with respect to a Party, then such Party shall not be entitled to hold Performance Assurance in the form of Cash and such Cash, if any, shall be held in a Qualified Institution pursuant to Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. If a Party is eligible to hold Cash pursuant to a selection in this Paragraph 10 but no Interest Rate is selected, then the Interest Rate for such Party shall be the Federal Funds Effective Rate as defined in Section VI of this Paragraph 10.

IX.

Other Changes. The following changes to the Collateral Annex shall be applicable. A.

Introduction. The first paragraph of the introduction is amended to read as follows: “This Collateral Annex, together with the Paragraph 10 Cover Sheet, (the “Transition Collateral Annex”) supplements, forms a part of, and is subject to the EEI Master Power Purchase and Sale Agreement dated as of _________October 15, 2012 between _________Kern River Cogeneration Company (“Party A”) and Southern California Edison Company (“Party B”), including the Cover Sheet and any other annexes thereto (as amended and supplemented from time to time, the “Agreement”). Capitalized terms used in this Transition Collateral Annex but not defined herein shall have the meanings given such terms in the Agreement.”

B.

Paragraph 1. Definitions. Amend Paragraph 1 as follows: i. The definition of “Credit Rating” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.12 of the Transition Master Agreement as modified in the Cover Sheet. ii. The definition of “Credit Rating Event” is amended by replacing “6(a)(iii)” with “6(a)(ii)”. iii. The definition of “Downgraded Party” is amended by replacing “6(a)(i)” with “6(a)(ii)”. iv. The definition of “Letter of Credit” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.27 of the Transition Master Agreement as modified in the Cover Sheet. v. The definition of “Letter of Credit Default” is amended by replacing the word “or” in the third line with the word “and”. vi. The definition of “Local Business Day” is amended by replacing the word “day” with “Business Day”.

77

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

vii. The definition of “Notification Time” is amended by replacing “11:00, New York” with “10:00 a.m. Pacific Prevailing.” viii. The definition of “Performance Assurance” is amended by replacing “6(a)(iv)” with “6(a)(iii)”. ix. The definition of “Qualified Institution” is amended as follows: “ “Qualified Institution” means a commercial bank or trust company organized under the laws of the United States or a political subdivision thereof, with (i) a Credit Rating of at least (a) "A-" by S&P, "A3" by Moody's, and “A-” by Fitch, if such entity is rated by all three Ratings Agencies; or (b) "A-" by S&P, "A3" by Moody's, or “A-” by Fitch, if such entity is rated by only two Ratings Agencies, and (ii) having a capital surplus of at least ONE BILLION AND 00/100 DOLLARS ($1,000,000,000.00).” x. The definition of “Reference Market-maker” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.671.71 of the Transition Master Agreement as modified in the Cover Sheet. xi. The definition of “Secured Party” is amended by replacing “3(b)” with “3(a)”. C.

Paragraph 3. Calculations of Collateral Requirement. In Paragraph 3(b)(2), is amended by replacing the comma after “Secured Party” with “and” and by deleting the phrase “, and any Interest Amount that has not yet been Transferred to the Pledging Party”.

D.

Paragraph 4. Delivery of Performance Assurance. In Paragraph 4, the penultimate sentence is amended by replacing the words “next Local Business Day” with “third Local Business Day thereafter” in clause (i), and by replacing the word “second” with fourth” in clause (ii).

E.

Paragraph 5. Reduction and Substitution of Performance Assurance. Amend Paragraph 5 as follows: i. Paragraph 5(a) is amended by deleting the parenthetical “(but no more frequently than weekly with respect to Letters of Credit and daily with respect to Cash)” from the first line. ii. The sixth sentence of Paragraph 5(a) is amended by inserting the word “Local” before “Business Day,” in clause (i) of that sentence.

F.

Paragraph 6. Administration of Performance Assurance. Amend Paragraph 6 as follows: i. Paragraph 6(a)(ii)(A) is amended by inserting “(other than subparagraph (B) below)” after “the provisions of this Paragraph 6(a)(ii)” in the first line thereof. ii. Paragraph 6(a)(ii)(B) is amended by replacing “Non-Downgraded Party” with “Downgraded Party”. iii. Paragraph 6(b)(iv) is amended by capitalizing the second instance of the word “cash” in the second sentence. iv. Paragraph 6(b)(v) is amended by replacing the parenthetical phrase “(including but not limited to the reasonable costs, expenses, and attorneys’ fees of the Secured Party)” with “(excluding attorneys’ fees)”.

G.

Paragraph 7. Exercise of Rights Against Performance Assurance. Paragraph 7(b) is amended by deleting it in its entirety and inserting the words “Intentionally Omitted.”.

H.

Paragraph 8. Disputed Calculations. Amend Paragraph 8 as follows:

88

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

i. Paragraph 8(a) is amended by adding in the third sentence the phrase “and, provided further, that if no quotations can be obtained, then the Secured Party’s original calculation shall be used” immediately after the words “then that quotation shall be used” and before the “)”. ii. Paragraph 8(b) is amended by (1) adding the words “requested by the Pledging Party” between the word “Assurance” and the phrase “to be reduced”, and (2) adding in the third sentence the phrase “and, provided further that, if no quotations can be obtained, then the Secured Party’s original calculation shall be used” immediately after the words “then that quotation shall be used” and before the “)”. I.

Paragraph 9. Covenants; Representations and Warranties; Miscellaneous. Section 9(d) is amended by deleting (i) the parenthetical phrase at the end of the first sentence, which reads, “(including, without limitation costs and reasonable fees and disbursements of counsel)” and (ii) the entire second sentence.

J.

Schedule 1 to Collateral Annex: Schedule 1 to the Collateral Annex is deleted in its entirety.

IN WITNESS WHEREOF, the Parties have caused this Paragraph 10 to the Transition Collateral Annex to be duly executed as of the Effective Date of the Agreement.October 15, 2012. Party A: KERN RIVER COGENERATION COMPANY

Party B: SOUTHERN CALIFORNIA EDISON COMPANY

By:

By:

Name: Neil Burgess

Name: Marc L. Ulrich

Title:

Title:

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

99

Document comparison by Workshare Professional on Monday, December 10, 2012 9:16:46 AM Input: Document 1 ID Description

Document 2 ID

Description Rendering set

file://J:\RAP Contract Origination\2011 CHP\03_Issue Package\Attachment D-2 - EEI Paragraph 10\Archive\Attachment D-2 - EEI_Para10_Coll_Annex.doc Attachment D-2 - EEI_Para10_Coll_Annex file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\Transition Contract Applications\2801 & 2058 - KRCC & Sycamore\Subsequent PPAs\Posting for Approval\20121012\KRCC Contract\20121011 KRCC Transition Para 10.DOCX 20121011 KRCC Transition Para 10 standard

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83

2012 CHP RA Capacity

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN [COUNTERPARTY(SELLER)]KERN RIVER COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY This confirmation letter ("“Confirmation"”) confirms the Transaction between [Counterparty]Kern River Cogeneration Company (“Seller” or “Kern River”) and Southern California Edison Company (“Buyer” or “SCE”), each individually a “Party” and together the “Parties”, dated as of [Date]October 15, 2012, (the "“Confirmation Effective Date"”) in which Seller agrees to provide to Buyer the right to the Product, as such term is defined in Article 2 of this Confirmation. This Transaction is governed by the Edison Electric Institute Master Power Purchase and Sale Agreement between the Parties, effective as of [Date],October 15, 2012, along with the Cover Sheet (the “Transition Cover Sheet:”), any amendments and annexes thereto (the "“Transition Master Agreement"”), and including, Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement”. Capitalized terms used but not otherwise defined in this Confirmation have the meanings ascribed to them in the Transition EEI Agreement, or the Tariff (defined herein below). RECITALS A.

Seller owns and operates Generating Unit # 1 and Generating Unit # 3, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement;

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement; and

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition Tolling Confirmation and the Transition PPA.

ARTICLE 1 DEFINITIONS 1.1 “Applicable Laws"” means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Body having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. 1.2

“Availability Incentive Payments” has the meaning set forth in the Tariff.

1.3

“Availability Standards” has the meaning set forth in the Tariff.

“Buyer" has the meaning specified in the introductory paragraph hereof. 1.4 “CAISO"” means the California Independent System Operator or any successor entity performing the same functions. “Capacity Attributes” means, with respect to a Generating Unit, any and all of the following, in each case which are attributed to or associated with the Generating Unit at any time throughout the Delivery Period: (a)

resource adequacy attributes, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward RAR;

1

2012 CHP RA Capacity

1.6

(b)

resource adequacy attributes or other locational attributes for the Generating Unit related to a Local Capacity Area, as may be identified from time to time by the CPUC, CAISO or other Governmental Body having jurisdiction, associated with the physical location or point of electrical interconnection of the Generating Unit within the CAISO Control Area, that can be counted toward a Local RAR;

(c)

flexible capacity resource adequacy attributes for the Generating Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward Flexible RAR; and

(d)

1.5 “Capacity Attributes” means any and allother current or future defined characteristics including flexibility, certificates, tags, credits, or accounting constructs, howsoever entitled, including any accounting construct counted toward any resource adequacy requirements, attributed to or associated with the Units throughout the Delivery PeriodRAR, Local RAR or Flexible RAR.

“Capacity Flat Price"” means the price specified in the Capacity Flat Price Table in Section 4.1.

1.7 “Capacity Replacement Price"” means the market price for the quantity of Product not provided by Seller under this Confirmation as determined in the manner upon which market prices are determined under Section 5.2(b) of the Transition Master Agreement. For purposes of Section 1.51 of the Transition Master Agreement, “Capacity Replacement Price” shall be deemed the “Replacement Price” for this Transaction. 1.8

“CHP” has the meaning set forth in Section 8.3.

“Confirmation” has the meaning specified in the introductory paragraph hereof. “Confirmation Effective Date” has the meaning specified in the introductory paragraph hereof. “Contingent Firm RA Product" has the meaning specified in Section 2.3 hereof. 1.9 “Contract Price"” means, for any Showing Month, the product of the Capacity Flat Price and the Price Shape for such period. 1.10 “Contract Quantity"” has the meaning set forth in Section 2.5.2.5 and means the total Unit Quantity for all Generating Units. 1.11 “CPUC Approval” means either (1) a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, or (2) a final and nonappealable disposition of the CPUC’s Energy Division, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation and, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA in their respective entirety, including payments to be made by SCEBuyer, subject to CPUC review of SCEBuyer’s administration of each of this Confirmation and, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. 1.12 “CPUC Decisions"” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 06-04-040, 06-06064, 06-07-031, 07-06-029, 08-06-031, 09-06-028, 10-06-036036, 11-06-022, 12-06-025, and any other existing or subsequent decisions, resolutions, or rulings related to resource adequacy, including, without limitation, the CPUC Filing Guide, in each case as may be amended from time to time by the CPUC. 1.13 “CPUC Filing Guide” is the annual document issued by the CPUC which sets forth the guidelines, requirements and instructions for LSE’s to demonstrate compliance with the CPUC’s RA program. 1.14

“Delivery Period"” has the meaning specified in Section 2.4.

1.15 “Exempt Wholesale Generator” means an unregulated power generator that is allowed to sell wholesale power s an independent energy producer, and is exempt from the Public Utility Holding Company Act of 1935.FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale

2

2012 CHP RA Capacity

transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. “Firm RA Product" has the meaning specified in the Section 2.2 hereof. “Flexible RAR” means the flexible capacity requirements, including, without limitation, maximum continuous ramping, load following, and regulation, established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Flexible RAR may also be known as ramping, maximum ramping, maximum continuous ramping, maximum continuous ramping capacity, maximum continuous ramping ramp rate, load following, load following capacity, load following ramp rate, regulation, regulation capacity, and/or regulation ramp rate. “Flexible RAR Showings” means the Flexible RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. 1.16

“GADS"” means the Generating Availability Data System, or its successor.

1.17 “Generating Facility” means the power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. The For purposes of this Confirmation, the Generating Facility shall include the Units.Generating Unit # 1 and Generating Unit # 3 for the Delivery Period set forth in Section 2.4. “Generating Unit” or “Generating Units” shall mean the generation assets described in Appendix A (including any Replacement Units), from which Product is provided by Seller to Buyer. Unless otherwise stated in this Confirmation, references to Generating Unit or Generating Units shall be applicable only to Generating Until # 1 and Generating Unit # 3 throughout the Delivery Period. “Generating Unit # 1” means the Generating Unit described in Appendix A(a). “Generating Unit # 3” means the Generating Unit described in Appendix A(c). 1.18 “Governmental Body"” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal. 1.19

“Local Capacity Area” has the meaning set forth in the Tariff.

1.20

"Local RA Attributes" means, with respect to a Unit, any and all resource adequacy attributes or other locational attributes for the Unit related to a Local Capacity Area, as may be identified from time to time by the CPUC, CAISO or other Governmental Body having jurisdiction, associated with the physical location or point of electrical interconnection of the Unit within the CAISO Control Area, that can be counted toward a Local RAR, but exclusive of any RA Attributes.

1.21 “Local RAR"” means the local resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Local RAR may also be known as local area reliability, local resource adequacy, local resource adequacy procurement requirements, or local capacity requirement in other regulatory proceedings or legislative actions. 1.22 “Local RAR Showings"” means the Local RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and, to the extent authorized by the CPUC, to the

3

2012 CHP RA Capacity

CAISO) pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. 1.23

“LSE"” means load-serving entity.

“Monthly Delivery Period” means each calendar month during the Delivery Period and shall correspond to each Showing Month. 1.24

“Monthly Payment"” has the meaning specified in Section 4.1.

1.25

“NERC"” means the North American Electric Reliability Corporation, or its successor.

1.26 “NERC/GADS Protocols"” means the GADS protocols established by NERC, as may be updated from time to time. 1.27

“Net Qualifying Capacity” has the meaning set forth in the Tariff.

1.28

“Non-Availability Charges” has the meaning set forth in the Tariff.

1.29 “Outage"” means any disconnection, separation or reduction in the capacity of any Generating Unit, other than a Planned Outage but including, without limitation, any such disconnection, separation or reduction in capacity that is designated as either forced or unplanned pursuant to the Tariff or the NERC/GADS Protocols. “Outage Schedule” has the meaning specified in Section 7.1. 1.30 “Planned Outage" means, subject to and as further described in the CPUC Decisions, a CAISOapproved planned or scheduled disconnection, separation or reduction in capacity of any Unit that is conducted for the purposes of carrying out routine repair or maintenance of such Unit, or for the purposes of new construction work for such Unit. ” means an Approved Maintenance Outage (as defined in the Tariff), but does not include a RA Maintenance Outage with Replacement (as defined in the Tariff), a Short-Notice Opportunity RA Maintenance Outage (as defined in the Tariff) or an Off-Peak Opportunity RA Maintenance Outage (as defined in the Tariff). 1.31 “Power Rating” means the electrical power output value indicated on the generating equipment nameplate. 1.32

"Price Shape" means the Price Shape specified in the Monthly Payment Price Shape Table in Section 4.1.

1.33

"Product" has the meaning specified in Section 2.1.

“Product” means the Capacity Attributes of the Generating Unit, provided that: (a)

Product does not include any right to the energy or ancillary services from the Generating Units;

(b)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Local Capacity Areas that results in a decrease or increase in the amount of Capacity Attributes related to a Local Capacity Area provided hereunder will not result in a change in payments made pursuant to this Transaction;

(c)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Flexible RAR, Capacity Attributes related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR, that results in a decrease or increase in the amount of Capacity Attributes related to Flexible RAR provided hereunder will not result in a change in payments made pursuant to this Transaction;

(d)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Local Capacity Areas whereby the a Generating Unit subsequently qualifies for a Local Capacity Area, the Product shall include all Capacity Attributes related to such Local Capacity Area; and

(e)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Flexible RAR, Capacity Attributes

4

2012 CHP RA Capacity

related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR whereby the a Generating Unit subsequently qualifies for to satisfy Flexible RAR, the Product shall include all Capacity Attributes related to Flexible RAR. 1.34 “PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. 1.35 “Qualifying Facility” means an electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of selfcertification pursuant to 18 CFR Part 292.207(a). 1.36

"RA Attributes" means, with respect to a Unit, any and all resource adequacy attributes, as may be identified from time to time by the CPUC, or other Governmental Body having jurisdiction, that can be counted toward RAR, exclusive of any Local RA Attributes.

1.37 “RAR"” means the resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. 1.38 “RAR Showings"” means the RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. 1.39

“Replacement Capacity"” has the meaning specified in Section 5.2.

1.40

“Replacement Unit"” means a generating unit meeting the requirements specified in Section 5.1.

1.41 “Resource Category"” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “Resource ID” has the meaning set forth in the Tariff. 1.42

“Scheduling Coordinator” or “SC” has the meaning set forth in the Tariff.

1.43 “Settlement Agreement” means the Qualifying Facility and Combined Heat and Power Program Settlement Agreement, approved by the CPUC in Decision 10-12-035 issued on December 21, 2010.2010, effective November 23, 2011. “Seller” has the meaning specified in the introductory paragraph hereof. “Shortfall Capacity” has the meaning set forth in Section 3.4. 1.44 “Showing Month” shall be the calendar month of the Delivery Period that is the subject of the RAR Showing, Local RAR Showing or Flexible RAR Showing, in each case, as set forth in the CPUC Decisions and outlined in the Tariff. For illustrative purposes only, pursuant to the Tariff and CPUC Decisions in effect as of the Confirmation Effective Date, the monthly RAR Showing made in June is for the Showing Month of August. 1.45

“Substitute Capacity” has the meaning set forth in Section 10.1.

1.46

“Substitution Rules” has the meaning set forth in Section 10.2.

1.47

“Supply Plan"” has the meaning set forth in the Tariff.

1.48 “Tariff"” means the tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. 1.49 “Term” shall have the following meaning: The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied.

5

2012 CHP RA Capacity

1.50

“Transition Agreement” has the meaning specified in the introductory paragraph hereof.

“Transition Collateral Annex” has the meaning specified in the introductory paragraph hereof. “Transition Cover Sheet” has the meaning specified in the introductory paragraph hereof. “Transition Master Agreement” has the meaning specified in the introductory paragraph hereof. “Transition PPA” has the meaning set forth in the Transition Cover Sheet. “Transition Tolling Confirmation” means that certain Tolling Confirmation of even date herewith between Seller and SCEBuyer, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. 1.51

"Unit" or "Units" shall mean the generation assets described in Appendix A (including any Replacement Units), from which Product is provided by Seller to Buyer.

1.52 “Unit NQC” means the Net Qualifying Capacity set by the CAISO for the applicable Generating Unit. The Parties agree that if the CAISO adjusts the Net Qualifying Capacity of a Generating Unit after the Confirmation Effective Date, that for the period in which the adjustment is effective, the Unit NQC shall be deemed the lesser of (i) the Unit NQC as of the Confirmation Effective Date, or (ii) the CAISOadjusted Net Qualifying Capacity. 1.53 “Unit Quantity"” means the amount of Product (in MWs) provided by Seller to Buyer by each individual Generating Unit identified in Appendix ASection 2.5 during the portions of the Delivery Period the Generating Unit is subject to the obligations of this Confirmation and subject to reductions as outlined in Section 3.2.

ARTICLE 2 TRANSACTION 2.1

Product[Intentionally omitted]

The RA Attributes, Local RA Attributes and Capacity Attributes of the Unit(s) identified in Appendix A (collectively, the “Product”). Product does not include any right to the energy or ancillary services from the Unit. Any change by the CAISO, CPUC or other Governmental Body that defines new or re-defines existing Local Capacity Areas that result in a decrease or increase in the amount of Local RA Attributes provided hereunder will not result in a change in payments made pursuant to this Transaction. In addition, the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Local Capacity Areas whereby the Units qualify for a Local Capacity Area, the Product shall include such Local RA Attributes. 2.2

Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity. for each day of each month of the Delivery Period If the Generating Units are not available to provide the full amount of the Contract Quantity for each day of a Showing Month for any reason, including without limitation any Outage or Planned Outage or any adjustment of the RA Attributes, Local RA Attributes and Capacity Attributes of any Generating Unit, Seller shall provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1 hereof. If Seller fails to provide Buyer with Replacement Capacity from Replacement Units pursuant to Section 5.1, then Seller shall be liable for damages and/or to indemnify Buyer for penalties or fines pursuant to the terms of Article Five. The Parties agree that Section 3.2 shall not apply if this Section 2.2 has been elected. 2.3

Contingent Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity for each day of each month of the Delivery Period. If the Generating Units are not

6

2012 CHP RA Capacity

available to provide the full amount of the Contract Quantity for each day of a Showing Month, Seller may elect to provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1. In such case, if Seller elects to provide Replacement Capacity pursuant to Section 5.1 and fails or if Seller elects not to provide such Replacement Capacity, then Seller shall be liable for damages and/or shall indemnify Buyer for penalties or fines pursuant to the terms of Article Five. If the Generating Units provide less than the full amount of the Contract Quantity in the event of a Planned Outage or a reduction to Unit NQC, Seller is not obligated to provide Buyer with Replacement Capacity and shall not be liable for damages or obligated to indemnify Buyer for penalties or fines pursuant to Article 5 hereof. Notwithstanding anything to the contrary set forth in this Confirmation, Seller has no obligation to deliver, and Buyer has no obligation to make a Monthly Payment for the Product for the Monthly Delivery Period if the Showing Month for the applicable month occurred before CPUC Approval. 2.4

Delivery Period

The “Delivery Period” shall be: [Start Date] through [End Date], inclusive, unless terminated earlier in accordance with the terms ofthe later of (a) October 15, 2012, or (b) the date when this Agreement has received both CPUC Approval and FERC Approval; provided, however, that: (i) before the commencement of the Delivery Period, SCE must have obtained or waived CPUC Approval and (ii) the Delivery Period must commence within 24 months of the Confirmation Effective Date. notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition Tolling Confirmation and the Transition PPA have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), through June 30, 2015.

7

2012 CHP RA Capacity

2.5

Contract Quantity

The Contract Quantity equals the total sum of each Unit Quantity identified in Appendix A. As of the Confirmation Effective Date, the Contract Quantityfor each day of each applicable Showing Month is as follows: Contract Quantity (MWs) Showing Month

2012

2013

2014

2015

8

2012 CHP RA Capacity

Generating Unit # 1 Contract Quantity (MWs) Showing Month

2012

Generating Unit # 3 Contract Quantity (MWs)

2013

2014

2015

January

77

77

77

February

77

77

March

77

April

Showing Month

2012

2013

2014

2015

January

77

77

77

77

February

77

77

77

77

77

March

77

77

77

77

77

77

April

77

77

77

May

77

77

77

May

77

77

77

June

77

77

77

June

77

77

77

July

77

77

July

77

77

August

77

77

August

77

77

September

77

77

September

77

77

October

77

77

77

October

77

77

77

November

77

77

77

November

77

77

77

December

77

77

77

December

77

77

77

ARTICLE 3 DELIVERY OBLIGATIONS 3.1

Delivery of Product

Subject to any reductions set forth in Section 3.2 (if Section 2.3 above is selected), Seller shall provide Buyer with the Contract Quantity of Product for each day of each Showing Month consistent with the following: (a)

Seller shall, on a timely basis, submit, or cause each Generating Unit's SC to submit, Supply Plans in accordance with the Tariff to identify and confirm the Unit Quantity provided to Buyer for each day of each Showing Month so that the total amount of Unit Quantity identified and confirmed for each day of such Showing Month equals the Contract Quantity for such day of such Showing Month, unless specifically requested not to do so by the Buyer.

(b)

Seller shall cause each Generating Unit’s SC to submit written notification to Buyer, no later than fifteen (15) Business Days before the relevant deadline for any applicable RAR orShowing, Local RAR Showing or Flexible RAR Showing, that Buyer will be credited with the Unit Quantity for each day of the Delivery PeriodShowing Month in the Generating Unit’s SC Supply Plan so that the total amount of Unit Quantity for each day of such Showing Month credited equals the Contract Quantity.

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2012 CHP RA Capacity

3.2

Adjustments to Contract Quantity

In the event that Section 2.3 is applicable, then: (a)

Seller’s obligation to deliver the Contract Quantity of Product for anyeach day of each Showing Month may be reduced if any portion of the Generating Unit(s) is scheduled for a Planned Outage during that month for the applicable days of such Planned Outage; provided, Seller notifies Buyer, no later than fifteen (15) Business Days before the relevant deadline for the corresponding RAR Showing or, Local RAR Showing or Flexible RAR Showing applicable to that monthShowing Month, the amount of Product from each Generating Unit Buyer is permitted to include in Buyer’s RAR orShowing, Local RAR Showing or Flexible RAR Showing applicable to that month as a result of such Planned Outage. In the event Seller is unable to provide the Contract Quantity of Productfor any portion of a Showing Month because of a Planned Outage of a Generating Unit, Seller has the option, but not the obligation, to provide Product from Replacement Units; provided, Seller provides and identifies such Replacement Units consistent with Section 5.1. In addition, if Seller chooses not to provide Product from Replacement Units and a Generating Unit is on a Planned Outage for any portion of the applicable Showing Month, then, the Contract Quantity shall be revised in accordance with any applicable adjustments stipulated by the CPUC Filing Guide or CAISO guidelines in effect for the applicable portion of the Showing Month in which the Planned Outage occurs.

(b)

3.3

(b) Reductions in Unit NQC: In the event the Generating Unit experiences a reduction in Unit NQC as determined by the CAISO; Seller has the option, but not the obligation, to provide the Unit Quantity from the same Generating Unit; provided the Generating Unit has sufficient remaining and available Product.

Buyer’s Re-Sale of Product

Buyer may re-sell all or a portion of the Product acquired hereunder. 3.4

Post-Showing Replacement Capacity

In the event CAISO determines, in accordance with the Tariff, that any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any portion of a Showing Month which was shown by Buyer in its RAR Showings, Local RAR Showings or Flexible RAR Showings requires outage replacement in accordance with Section 40.7 of the Tariff (“Shortfall Capacity”), (i) Seller’s Monthly Payment will be reduced in accordance with Section 4.1 below and, neither Seller, nor the Generating Unit’s SC (unless the Generating Unit’s SC is Buyer), shall have the right to provide Buyer with RA Replacement Capacity with respect to such Shortfall Capacity, (ii) Seller shall have no liability under Sections 5.2 or 5.3 below with respect to such Shortfall Capacity, except to the extent described in Section 10.3 below and (iii) Seller shall have no liability to Buyer for any costs which are allocated to Buyer by the CAISO for any RA Maintenance Outage Backstop Capacity procured by CAISO which was related to such Shortfall Capacity, except to the extent described in Section 10.3 below. Notwithstanding anything to the contrary in this Agreement, at any time that any of the proposed amendments to the Tariff relating to outage replacement, filed by the CAISO at FERC on September 20, 2012 (Docket ER 12-2669-000), have not been authorized by FERC, the provisions of this Section 3.4 shall not be applicable, and, for purposes of calculating Seller’s Monthly Payment under Section 4.1, “D” (Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month) shall equal zero.

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2012 CHP RA Capacity

ARTICLE 4 PAYMENT 4.1

Monthly Payment

In accordance with the terms of Article Six of the Transition Master Agreement, Buyer shall make a Monthly Payment to Seller for each Generating Unit, after the applicable Showing Month, as follows:

Monthly Payment = (A x B x 1,000) where: A = applicable Contract Price for that Showing Month B = Unit C = Contract Quantity provided by Seller to Buyer pursuant to and consistent with Section 3.1 for the applicable day of the Showing Month D = Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month i = Each day of Showing Month n = number of days in the Showing Month The Monthly Payment calculation shall be rounded to two decimal places. CAPACITY FLAT PRICE TABLE Contract Year

RA Capacity Flat Price ($/kW-month)

2012

1.18

2013

1.18

2014

1.18

2015

1.18

The respective monthly Price Shape, set forth in the Monthly Payment Price Shape Table below, shall apply throughout the entire Delivery Period.

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2012 CHP RA Capacity

MONTHLY PAYMENT PRICE SHAPE TABLE

4.2

Showing Month

Price Shape (%)

Jan

[ ]10%

Feb

[ ]5%

Mar

[ ]5%

Apr

[ ]5%

May

[ ]15%

Jun

[ ]40%

Jul

[ ]365%

Aug

[ ]490%

Sep

[ ]205%

Oct

[ ]25%

Nov

[ ]15%

Dec

[ ]20%

Allocation of Other Payments and Costs (a)

Seller shall retain any revenues it may receive from and pay all costs charged by the CAISO or any other third party with respect to any Generating Unit for (i) start-up, shutdown, and minimum load costs, (ii) capacity revenue for ancillary services, (iii) energy sales, and (iv) any revenues for black start or reactive power services.

(b)

Buyer shall be entitled to receive and retain all revenues associated with the Contract Quantity of Product during the Delivery Period (including any capacity revenues from RMR Contracts for any Generating Unit, Capacity Procurement Mechanism (CPM), or its successor, and Residual Unit Commitment (RUC) Availability Payments, or its successor, but excluding payments described in Section 4.2(a)(i)-(iv) above).

(c)

In accordance with Section 4.1 of this Confirmation and Article Six of the Transition Master Agreement, (i) all such Buyer revenues described in this Section 4.2, but received by Seller, or a Generating Unit’s SC, owner, or operator shall be remitted to Buyer, and Seller shall pay such revenues to Buyer if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Buyer. If Seller fails to pay such revenues to Buyer, Buyer may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts itBuyer may owe to Seller under this Confirmation. In order to verify the accuracy of such revenues, Buyer shall have the right, at its sole expense and during normal working hours after reasonable prior notice, to hire an independent third party reasonably acceptable to Seller to audit any documents, records or data of Seller associated with the Contract Quantity; and

12

2012 CHP RA Capacity

(ii) all such Seller, or a Generating Unit’s SC, owner, or operator revenues described in this Section 4.2, but received by Buyer shall be remitted to Seller, and Buyer shall pay such revenues to Seller if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Seller. If Buyer fails to pay such revenues to Seller, Seller may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts it may owe to Buyer under this Confirmation. (d)

If a centralized capacity market develops within the CAISO region, Buyer will have exclusive rights to offer, bid, or otherwise submit the Contract Quantity provided to Buyer pursuant to this Confirmation for re-sale in such market, and retain and receive any and all related revenues.

(e)

Seller agrees that the Unit isGenerating Units are subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account.

ARTICLE 5 SELLER'S FAILURE TO DELIVER CONTRACT QUANTITY 5.1

Seller’s Duty To Provide Replacement Capacity

Subject to any adjustments made pursuant to Section 3.2(a) (if Section 2.3 above is selected), if Seller is unable to provide the full Contract Quantity of Product for day of any Showing Month, then:

5.2

(a)

Seller may, at no cost to Buyer, provide Buyer with replacement Product from one or more Replacement Units, such that the total amount of Product provided to Buyer from all Generating Units and Replacement Units for each day of the Showing Month equals the Contract Quantity; provided, that (i) replacement Product from any generating unit other than the generating units described in Section 5.1(a)(ii) may only be provided with Buyer’s consent, which may not be unreasonably or untimely withheld, and (ii) replacement Product from any of Seller’s generating units subject to the Transition PPA may only be provided with Buyer’s consent, which Buyer may give or withhold in Buyer’s sole discretion; and

(b)

Seller shall identify Replacement Units meeting the above requirements no later than fifteen (15) Business Days before the relevant deadline for Buyer's RAR Showing and/or Local RAR Showing.

(b)

Seller shall identify Replacement Units meeting the above requirements no later than fifteen (15) Business Days before the relevant deadline for Buyer's RAR Showing, Local RAR Showing and/or Flexible RAR Showing, provided, that the designation of any Replacement Unit by Seller shall be subject to Buyer’s prior written approval, which shall not be unreasonably withheld. Once Seller has identified in writing any Replacement Units that meet the requirements of this Section 5.1, any such Replacement Unit shall be automatically deemed a Generating Unit for purposes of this Confirmation for that Showing Month.

Damages for Failure to Provide Replacement Capacity

If either Section 2.2 or 2.3 is selected above and Seller fails to provide Buyer any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any day of any Showing Month or if Seller has elected to provide replacement Product in accordance with the terms of this Confirmation, but fails to provide

13

2012 CHP RA Capacity

such replacement Product from one or more Replacement Units for any Showing Month, then, in each case, the following shall apply:

5.3

(a)

Buyer may, but shall not be required to, replace any portion of the Contract Quantity not provided by Seller for any portions of each Showing Month with capacity having equivalent RA and Local RACapacity Attributes as the Product not provided by Seller ("“Replacement Capacity"”). Buyer may enter into purchase transactions with one or more parties to replace the portion of Contract Quantity not provided by Seller for all portions of each Showing Month. Additionally, Buyer may enter into one or more arrangements to repurchase its obligation to sell and deliver the capacity to another party, and such arrangements shall be considered the procurement of Replacement Capacity. Buyer shall act in a commercially reasonable manner in procuring any Replacement Capacity.

(b)

Seller shall pay to Buyer at the time set forth in Section 4.1 of the Transition Master Agreement, the following damages in lieu of damages specified in Section 4.1 of the Transition Master Agreement: an amount equal to the positive difference, if any, between (i) the sum of (A) the actual cost paid by Buyer for any Replacement Capacity, including any transaction costs and expenses incurred in connection with such procurement, plus (B) each Capacity Replacement Price times the aggregate amount of the Contract Quantity neither provided by Seller nor purchased by Buyer for all portions of the applicable Showing Month pursuant to Section 5.2(a), and (ii) the aggregate amount of Contract Quantity not provided for all applicable portions of the applicable Showing Month times the Contract Price for that month. If Seller fails to pay these damages, then Buyer may offset those damages owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement.

Indemnities for Failure to Deliver Contract Quantity

Subject to any adjustments made pursuant to Section 3.2(a), Seller agrees to indemnify, defend and hold harmless Buyer from any penalties, fines or costs assessed against Buyer by the CPUC or the CAISO, resulting from any of the following: (a)

Seller’s failure to provide any portion of the Contract Quantity, if Seller fails to replace the shortfall in Contract Quantity from Replacement Units in accordance with Section 5.1 for any portion of the Delivery Period;

(b)

Seller’s failure to provide notice of the non-availability of any portion of the Contract Quantity for any portion of the Delivery Period as required under Section 3.1; or

(c)

A Generating Unit’s SC’s failure to timely submit Supply Plans that identify Buyer’s right to the Unit Quantity purchased hereunder for each day of the Delivery Period.

With respect to the foregoing, the Parties shall use commercially reasonable efforts to minimize such penalties, fines and costs; provided, that in no event shall Buyer be required to use or change its utilization of its owned or controlled assets or market positions to minimize these penalties and fines. Seller will have no obligation to Buyer under this Section 5.3 in respect of the portion of Contract Quantity for which Seller has paid damages for Replacement Capacity. If Seller fails to pay those penalties, fines or costs, or fails to reimburse Buyer for those penalties, fines or costs, then Buyer may offset those penalties, fines or costs against any future amounts it may owe to Seller under this Confirmation.

ARTICLE 6 CAISO OFFER REQUIREMENTS Subject to Buyer’s request under Section 10.1, during the Delivery Period, except to the extent any Generating Unit is in an Outage or Planned Outage, Seller shall either schedule or cause the Generating

14

2012 CHP RA Capacity

Unit’s SC to schedule with, or make available to, the CAISO the Unit Quantity for each Generating Unit in compliance with the Tariff, and shall perform all, or cause the Generating Unit’s SC, owner, or operator, as applicable, to perform all obligations under the Tariff that are associated with the sale of Product hereunder. Buyer shall have no liability for the failure of Seller or the failure of any Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance, provided that Buyer in its capacity as SC shall remain liable for any failure by it to comply with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 7 PLANNED OUTAGES Upon the Confirmation Effective Date, thirty (30) days before the applicable year-ahead showing, and no later than January 1, April 1, July 1 and October 1 of each calendar year thereafter until the end of the Term, Seller shall submit, or cause the Generating Unit's SC to submit to Buyer, the portion of each Generating Unit's schedule of proposed Planned Outages ("“Outage Schedule"”) for the following twelve (12) month period or until the end of the Delivery Period, whichever is shorter. Within twenty (20) Business Days after its receipt of an Outage Schedule, Buyer shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Good Utility Practices, accommodate Buyer's requests regarding the timing of any Planned Outage. Seller or the Generating Unit's SC shall notify Buyer within five (5) Business Days of any change to the Outage Schedule.

ARTICLE 8 OTHER BUYER AND SELLER COVENANTS 8.1

Seller’s and Buyer’s Duty to Take Action to Allow the Utilization of the Product

Buyer and Seller shall, throughout the Delivery Period, take all commercially reasonable actions and execute any and all documents or instruments reasonably necessary to ensure Buyer's right to the use of the Contract Quantity for the sole benefit of Buyer's RAR and, Local RAR and Flexible RAR, if applicable. The Parties further agree to negotiate in good faith to make necessary amendments, if any, to this Confirmation to conform this Transaction to subsequent clarifications, revisions, or decisions rendered by the CPUC, FERC, CAISO or other Governmental Body having jurisdiction to administer RAR or, Local RAR or Flexible RAR, to maintain the benefits of the bargain struck by the Parties on the Confirmation Effective Date. 8.2

Seller’s Represents, Warrants and Covenants

Seller represents, warrants and covenants to Buyer that, throughout the Delivery Period: and to the extent such Generating Unit is then subject to the obligations of this Confirmation: (a)

Seller owns or has the exclusive right to the Product sold under this Confirmation from each Generating Unit, and shall furnish Buyer, CAISO, CPUC or other Governmental Body with such evidence as may reasonably be requested to demonstrate such ownership or exclusive right;

(b)

No portion of the Contract Quantity has been committed by Seller to any third party in order to satisfy RAR or Local RAR or Flexible RAR or analogous obligations in any CAISO or non-CAISO markets, other than pursuant to an RMR Contract between the CAISO and either Seller or the Generating Unit’s owner or operator;

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2012 CHP RA Capacity

(c)

Each Generating Unit is connected to the CAISO Controlled Grid, is within the CAISO Control Area, and is under the control of CAISO;

(d)

Seller shall, and each Generating Unit’s SC, owner and operator is obligated to, comply with Applicable Laws, including the Tariff, relating to the Product;

(e)

If Seller is the owner of any Generating Unit, the aggregation of all amounts of Local RA Attributes and RACapacity Attributes that Seller has sold, assigned or transferred for any Generating Unit does not exceed the Unit NQC for that Generating Unit;

(f)

Seller has notified the SC of each Generating Unit that (i) Seller has transferred the Unit Quantity with respect to each day of each Showing Month to Buyer, and (ii) the SC is obligated to deliver the Supply Plans in accordance with the Tariff;

(g)

Seller has notified the SC of each Generating Unit that Seller is obligated to cause each Generating Unit’s SC to provide to the Buyer, at least fifteen (15) Business Days before the relevant deadline for each RAR orShowing, Local RAR Showing or Flexible RAR Showing, the Unit Quantity of each Unitfor each day of such Showing Month of each Generating Unit which is subject to the obligations of this Confirmation that is to be submitted in the Supply Plan associated with this AgreementConfirmation for the applicable period; and

(h)

Seller has notified each Generating Unit’s SC that (i) Buyer is entitled to the revenues set forth in Section 4.2,4.2 and (ii) such SC is obligated to promptly deliver those revenues to Buyer, along with appropriate documentation supporting the amount of those revenues.; and

(i)

Buyer shall have no liability for the failure of Seller or the failure of the Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance.

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2012 CHP RA Capacity

8.3

Combined Heat and Power (“CHP”) Program Provisions; CPUC Approval; FERC Approval (a)

CHP Program Procurement and Seller Eligibility Seller and SCEBuyer acknowledge and agree that SCEBuyer is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by SCEBuyer pursuant to this Confirmation is and shall be deemed by the Parties to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to SCE that (a) the Generating Facility met the PURPA efficiency requirements (18 Code of Federal Regulations, Part 292, Section 292.205) as of September 2007; (b)Buyer that as of the Confirmation Effective Date, the Power Rating of the Generating Facility equals [___] MW; and (c) as of the Confirmation Effective Date, the Generating Facility is a [Unit # 1 and Generating Unit # 3, together with the generating units that are subject to the obligations in the Transition PPA is a Qualifying Facility][Exempt Wholesale Generating Facility].Notwithstanding anything to the contrary set forth in this Agreement, Seller covenants that the Power Rating of the Generating Facility shall always exceed 5 MW..

(b)

CPUC Approval (i) Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use commercially reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party. (ii) Either Party has the right to terminate this Transaction and this Confirmation on notice, which will be effective five Business Days after such notice is given, if CPUC Approval has not been obtained or waived by SCE in its sole discretion within 365 days after SCE files its request for CPUC Approval and a notice of termination is given on or before the 395th day after SCE files the request for CPUC Approval.(iii) Failure to obtain CPUC Approval in accordance with this Section 8.3(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of SCEBuyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval.

(c)

Provision of Information Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement.

(d)

FERC Approval (i) Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereunder, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms

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2012 CHP RA Capacity

required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report. (ii) Failure to obtain FERC Approval in accordance with this Section 8.3(d) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

ARTICLE 9 CONFIDENTIALITY Notwithstanding Section 10.11 of the Transition Master Agreement, the Parties agree that Buyer may disclose the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to any Governmental Body, the CPUC, the CAISO in order to support its Local RAR orShowings, RAR Showings or Flexible RAR Showings, if applicable, and Seller may disclose the transfer of the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to the SC of each Generating Unit in order for such SC to timely submit accurate Supply Plans; provided, that each disclosing Party shall use reasonable efforts to limit, to the extent possible, the ability of any such applicable Governmental Body, CAISO, or SC to further disclose such information. In addition, in the event Buyer resells all or any portion of the Product to another party, Buyer shall be permitted to disclose to the other party to such resale transaction all such information necessary to effect such resale transaction.

ARTICLE 10 GENERATING UNIT SUBSTITUTION 10.1

Substitute Capacity

No later than five (5) Business Days before the relevant deadline for each RAR orShowing, Local RAR Showing or Flexible RAR Showing, Buyer may request that Seller not list, or cause each Generating Unit’s SC not to list, a portion or all of a Generating Unit’s Unit Quantity for any portion of a Showing Month on the Supply Plan. The amount of Unit Quantity that is the subject of such a request shall be known as “Substitute Capacity” and, for purposes of calculating a Monthly Payment pursuant to Section 4.1, be deemed Unit Quantity provided consistent with Section 3.1. Seller shall, or shall cause each Generating Unit’s SC to, comply with Buyer’s request under this Section 10.1. 10.2

Seller’s Obligations With Respect to Substitute Capacity

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2012 CHP RA Capacity

If Buyer makes a request for Substitute Capacity, Seller shall (a) make such Substitute Capacity available to Buyer during the applicable Showing Month in order to allow Buyer to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”); and (b) take all action, or cause each Generating Unit’s SC to take all action, to allow Buyer to utilize the Substitution Rules, including, but not limited to, ensuring that the Substitute Capacity will qualify for substitution under the Substitution Rules and providing Buyer with all information needed to utilize the Substitution Rules. Seller agrees that all Substitute Capacity that is utilized under the Substitution Rules is subject to the requirements identified in Article 6 as if the capacity had been included on the Supply Plan. 10.3

Failure to Provide Substitute Capacity

If Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitute Capacity under the Substitution Rules, then Seller shall pay for any and all Non-Availability Charges incurred by Buyer for such failure or inability to utilize the Substitution Rules; provided, that if Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitution Rules, in each case, because the Substitute Capacity does not qualify for substitution under the last sentence of Section 40.9.4.2.1(1) of the Tariff or under the last sentence of Section 40.9.4.2.1(2) of the Tariff, then Seller shall not be responsible for any such Non-Availability Charges described in this Section 10.3 associated with such inability. If Seller fails to pay any Non-Availability Charges under this Section 10.3, then Buyer may offset those charges owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement. 10.4

Notwithstanding anything to the contrary in this Confirmation, Article 10 shall not apply to this Confirmation at any time during which Buyer is the SC.

ARTICLE 11 MARKET BASED RATE AUTHORITY Seller agrees, in accordance with FERC Order No. 697, to, upon request of Buyer, submit a letter of concurrence in support of any affirmative statement by Buyer that this contractual arrangement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR § 35.42. Seller also agrees that it will not, in any filings, if any, made subject to Order Nos. 652 and 697, claim that this contractual arrangement conveys ownership or control of generation capacity from Seller to Buyer.

ARTICLE 12 COLLATERAL REQUIREMENTS 12.1

Seller Collateral Requirements

Notwithstanding anything to the contrary contained in the Transition Master Agreement, Seller shall provide to, and maintain with, Buyer a Full Floating Independent Amount as long as Seller or its Guarantor, if any, does not maintain Credit Ratings of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency. The Full Floating Independent Amount shall be equal to $ [________] [20% of the sum of the Monthly Payments for the current month and all remaining months of the Delivery Period, without the reductions specified in Section 3.2].3.2. For the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Seller shall be added to the Exposure Amount for Buyer and subtracted from the Exposure Amount for Seller.

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2012 CHP RA Capacity

12.2

Current Mark-to-Market Value

The Parties further agree that for the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, the Current Mark-to-Market Value for this Transaction is deemed to be zero. If at any time prior to the expiration of the Delivery Period, a liquid market for an RA Capacity product develops wherein price quotes for such a product can be obtained, the Parties agree to amend the Confirmation to include a methodology for calculating the Current Mark-to-Market Value for this Transaction, consequently affecting the Buyer’s Exposure. 12.3

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEI Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, with respect to this Transaction only (i) if Seller has Exposure to Buyer, then the amount of Exposure for this Transaction is deemed to be zero dollars ($0), and (ii) in no event shall Buyer be required to post or maintain an Independent Amount with Seller.

ARTICLE 13 OTHER 13.1 13.1 Declaration of an Early Termination Date and Calculation of Settlement Amounts Notwithstanding anything to the contrary, the Parties shall determine the Settlement Amount for this Transaction in accordance with Section 5.2 of the Transition Master Agreement. Furthermore, with respect to this Transaction only, the following language is to be added at the end of Section 5.2 of the Transition Master Agreement: “If Buyer is the Non-Defaulting Party and Buyer reasonably expects to incur penalties, fines or costs from the CPUC, the CAISO, or any Governmental Body having jurisdiction, because Buyer is not able to include the applicable Contract Quantity in any applicable RAR Showing or, Local RAR Showing or Flexible RAR Showing due to Seller’s Event of Default, then Buyer may, in good faith, estimate the amount of those penalties or fines and include this estimate in its determination of the Settlement Amount, subject to accounting to Seller when those penalties or fines are finally ascertained. If this accounting establishes that Buyer’s estimate exceeds the actual amount of penalties or fines, Buyer shall promptly remit to Seller the excess amount. The rights and obligations with respect to determining and paying any Settlement Amount or Termination Payment, and any dispute resolution provisions with respect thereto, shall survive the termination of this Transaction and shall continue until after those penalties or fines are finally ascertained.” 13.2

Termination Right of Seller; Settlement Amount (i)

Seller has the right to terminate this Confirmation if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected by Buyer in a competitive solicitation. In such an instance, the termination of this Confirmation will be effective as of midnight the day before the commencement of any delivery period for any electric energy, capacity or attributes from the Generating Facility which is selected by Buyer in such competitive solicitation.

(ii)

Seller has the right to terminate this Confirmation upon providing to Buyer at least 180 days advance notice if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected in a competitive solicitation by a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-

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2012 CHP RA Capacity

owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 13.2(b) at a later date so long as Seller provides Buyer at least 90 days advance Notice. (iii)

Seller has the right to terminate this Confirmation upon providing to Buyer at least 180 days advance notice if Seller (or any venture in which Seller is a participant) and the Generating Facility jointly enter into an agreement for the sale of electric energy, capacity or attributes with a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement; provided, however, if Seller has entered into an agreement with a California investor-owned utility (other than Buyer), but any regulatory approval from the CPUC necessary for the commencement of such agreement has not been obtained or waived prior to 180 days before the start date of such agreement, Seller may provide the Notice required under this Section 13.2(c) at a later date so long as Seller provides Buyer at least 90 days advance Notice.

(iv)

Notwithstanding anything to the contrary, no Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation under Section 13.2.

ACKNOWLEDGED AND AGREED TO AS OF [__________________],OCTOBER 15, 2012: [Seller]

Kern River Cogeneration Company

Southern California Edison Company

By:

By:

Name: Neil Burgess

Name: Marc L. Ulrich

By:

By:

Name:

Name:

Title:

Title:

Date:

Date:

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

Date:

Date:

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2012 CHP RA Capacity

APPENDIX A GENERATING UNIT INFORMATION (a)

Generating Unit # 1 Name: ___________________Kern River Cogeneration Company Generating Unit # 1

Location: _________________ CAISO Resource ID: ______________ Unit NQC (as of the Confirmation Effective Date): __________ MW Unit Quantity: ___________ MW Bakersfield, California Resource Type: _________________ Other- Frame7E Resource Category (1, 2, 3 or 4): _________ 4 Point of interconnection with the CAISO Controlled Grid ("Substation"): ________ “Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): _____ South Local Capacity Area (if any, as of Confirmation Effective Date): ________ Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: ____________________________________________________________ Run Hour Restrictions: ____________________ None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour (b)

Generating Unit # 3 Name: Kern River Cogeneration Company Generating Unit # 3

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2012 CHP RA Capacity

Location: Bakersfield, California Resource Type: Other- Frame7E Resource Category (1, 2, 3 or 4): 4 Point of interconnection with the CAISO Controlled Grid (“Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): South Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour

23

Document comparison by Workshare Professional on Monday, December 10, 2012 9:18:43 AM Input: Document 1 ID Description

Document 2 ID

Description Rendering set

file://J:\RAP Contract Origination\2011 CHP\08_Document Control\Track 1\~Pro Forma Changes\UPF Documents\RA Confirm\RA Pro Forma Changes - APPROVED 06202012 clean.docx RA Pro Forma Changes - APPROVED 06202012 clean file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\Transition Contract Applications\2801 & 2058 - KRCC & Sycamore\Subsequent PPAs\Posting for Approval\20121012\KRCC Contract\20121012 KRCC Transition RA.DOC 20121012 KRCC Transition RA standard

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Total changes

694

EEI Master Agreement Cover Sheet SCE version09.12.11

[THIS MASTER AGREEMENT IS SUBJECT TO SCE MANAGEMENT REVIEW AND APPROVAL1]MASTER POWER PURCHASE AND SALE AGREEMENT COVER SHEET This Master Power Purchase and Sale Agreement (Version 2.1; modified 4/25/00) (“Master Agreement” or “Transition Master Agreement”) is made as of the following date: ________________2October 15, 2012 (“Effective Date”). The Transition Master Agreement, together with the exhibits, schedules and any written supplements hereto, the Party A Tariff, if any, the Party B Tariff, if any, any designated collateral, credit support, margin agreement, or similar arrangement between the Parties and all Transactions (including any confirmations accepted in accordance with Section 2.3 hereto) shall be referred to as the “Agreement”. The Parties to this Transition Master Agreement are the following: Name: ___________________________Sycamore Cogeneration Company (“Party A”)

Name: Southern California Edison Company (“Party B”)

All Notices:

All Notices:

Street: P. O. Box 80598

Street: 2244 Walnut Grove Ave., G.O.1, Quad 1C

City: Bakersfield

1 2

City: Rosemead, CA

Zip: 93380

Zip: 91770

Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610 Duns: 18-507-4887 Federal Tax ID Number: 95-4014893

Attn: Contract Administration Phone: (626) 302-3126 Facsimile: (626) 302-8168 Duns: 006908818 Federal Tax ID Number: 95-1240335

Invoices: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Invoices: Attn: Power Procurement - Finance Phone: (626) 302-3277 Facsimile: (626) 302-3276 Email: [email protected]@sce.co m

Scheduling: Attn: Control Room Phone: 661-615-4704 Facsimile: 661-615-4664

Scheduling: Attn: Manager of Energy Operations Phone: (626) 302-5730 Facsimile: (626) 307-4413

Payments: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Payments: Attn: Accounts Receivable - Power Procurement Southern California Edison Company PO Box 800 Rosemead, CA 91770 Phone: (626) 302-9371 Facsimile: (626) 302-9392

Wire Transfer: BNK: JP Morgan Chase ABA: 021-0000-21 ACCT: 910-2588-705

Wire Transfer: BNK: JPMorganChaseJPMorgan Chase Bank ABA: 021000021 ACCT: 323-394434

[SCE Comment: Green highlights are comments or instructions to be deleted prior to final execution.] [SCE Comment: Blue highlights indicate required information to be completed prior to final execution.] 11

EEI Master Agreement Cover Sheet SCE version09.12.11

Credit and Collections: Attn: Accounting Department Phone: 661-615-4630 Facsimile: 661-615-4610

Credit and Collections: Attn: Manager of Credit Phone: (626) 302-3383 Facsimile: (626) 302-2517

Confirmations: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

Confirmations: Attn: Confirmation Coordinator Phone: (626) 307-4485 Facsimile: (626) 302-3410

With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: 661-615-4630 Facsimile: 661-615-4610

With additional Notices of an Event of Default or Potential Event of Default to: Southern California Edison Company 2244 Walnut Grove Ave., G.O.1, Quad 1C Rosemead, CA 91770 Attn: Manager of Energy Contracts Phone: (626) 302-3312 Facsimile: (626) 302-8168

The Parties hereby agree that the General Terms and Conditions are incorporated herein, and to the following provisions as provided for in the General Terms and Conditions: Party A Tariff

Tariff Original Volume No. 1

Party B Tariff

Tariff Original Vol. No. 8

Dated March 21, 2010 Docket Number ER10-611-000 Dated 09/01/2002

22

Docket Number ER 02-2263-000

EEI Master Agreement Cover Sheet SCE version09.12.11

Article Two Transaction Terms and Conditions

Optional provision in Section 2.4. If not checked, inapplicable.

Article Four Remedies for Failure to Deliver or Receive

Accelerated Payment of Damages. If not checked, inapplicable.

Article Five Events of Default; Remedies

5.1(g) Cross Default for Party A: Party A: Sycamore Cogeneration Company Other Entity:[Guarantor, if applicable]

Cross Default Amount $________ [Amount and/or Methodology To Be Negotiated]1,000,000 Cross Default Amount $_____NA___ [Amount and/or Methodology To Be Negotiated]

5.1(g) Cross Default for Party B: Party B: Southern California Edison Company.

Cross Default Amount $________ [Amount and/or Methodology To Be Negotiated]75,000,000

Other Entity: Not Applicable.

Cross Default Amount $________ [Amount and/or Methodology To Be Negotiated]

5.6 Closeout Setoff Option A, as amended. Option B - Affiliates shall have the meaning set forth in the Agreement unless otherwise specified as follows: Option C (No Setoff). Article Eight

[ARTICLE EIGHT PROVISIONS TO BE NEGOTIATED BY CREDIT GROUPS]

Credit and Collateral Requirements

8.1 Party A Credit Protection: (a) Financial Information: Option A, as amended. Option B Specify: Option C Specify:

33

EEI Master Agreement Cover Sheet SCE version09.12.11

(b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex.

(d) Downgrade Event: Not Applicable. Applicable. If applicable, complete the following: It shall be a Downgrade Event for Party B if Party B’s Credit Rating falls below ______ from S&P or _________ from Moody's or ______ from Fitch or if Party B is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party B: Not Applicable. Guarantee Amount: Not Applicable. 8.2 Party B Credit Protection: (a) Financial Information: Option A, as amended. Option B, as amended. Specify: [Guarantor or other party specified, if applicable]________________ Option C Specify: ___________ (b) Credit Assurances: Not Applicable. Applicable. (c) Collateral Threshold: Not Applicable. Applicable, as specified in Paragraph 10 to the EEI Collateral Annex. (d) Downgrade Event: Not Applicable. Applicable.

44

EEI Master Agreement Cover Sheet SCE version09.12.11

If applicable, complete the following: It shall be a Downgrade Event for Party A if Party A’s Credit Rating falls below ___ from S&P or ___ from Moody's or ______ from Fitch or if Party A is not rated by any Ratings Agency. Other: Specify: (e) Guarantor for Party A: Guarantee Amount: $__________ Article Ten Confidentiality Schedule M

Confidentiality Applicable. If not checked, inapplicable. Party A is a Governmental Entity or Public Power System. Party B is a Governmental Entity or Public Power System. Add Section 3.6. If not checked, inapplicable. Add Section 8.4. If not checked, inapplicable.

55

EEI Master Agreement Cover Sheet SCE version09.12.11

Other Changes

The following changes shall be applicable. ARTICLE ONE: GENERAL DEFINITIONS. Amend Article One as follows: Section 1.4 is amended by (i) deleting the word “or” in the first line, and (ii) inserting the words “, or the Friday immediately following the U.S. Thanksgiving holiday” immediately after “Bank holiday”. Section 1.11 is amended by (i) deleting the words “attorneys’ fees and” and (ii) inserting the words “(excluding attorneys’ fees)” after the word “expenses” in the fifth line. Section 1.12 is amended by replacing the word “issues” in the fourth line with the word “issuer”, and replacing the phrase “S&P, Moody’s or any other rating agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement” with the phrase “the Ratings Agencies”. Section 1.24 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.27 is amended to read as follows: “1.27 ‘Letter of Credit’ means an irrevocable, nontransferable standby letter of credit, issued by a major U.S. commercial bank or the U.S. branch office of a foreign bank with, in either case, a Credit Rating of at least (a) A- by S&P, A3 by Moody’s, and A- by Fitch, if such entity is rated by the Ratings Agencies; or (b) A- by S&P, A3 by Moody’s, or A- by Fitch, if such entity is rated by only one or two of the Ratings Agencies, in substantially the form attached hereto as Schedule 1, with such changes to the terms in that form as the issuing bank may require and as may be acceptable to the beneficiary thereof. Costs of a Letter of Credit shall be borne by the applicant for such Letter of Credit.” Section 1.28 is amended by inserting the words “in accordance with Section 5.2(b)” immediately after “reasonable manner”. Section 1.29 is amended by inserting the words “or ‘Transition Master Agreement’ ” immediately after “Master Agreement”. Section 1.50 is amended by replacing the term “Section 2.4” with the term “Section 2.5”. Section 1.51 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, from an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Buyer’s option,” the phrase “absent a purchase from an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. Section 1.53 is amended by (i) deleting the phrase “at the Delivery Point” and replacing it with “, to an entity that is not an Affiliate of either Party,”; (ii) in clause (ii) inserting after the phrase “at Seller’s option,” the phrase “absent a sale to an entity that is not an Affiliate of either Party,”; and (iii) in the last sentence thereof deleting the phrase “at the Delivery Point” and replacing it with “that is not an Affiliate of either Party”. New Sections 1.62, 1.63, 1.64, 1.65, 1.66, 1.67, 1.68, 1.69, 1.70, 1.71 and 1.681.72

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are added to read as follows: “1.62 ‘CPUC Approval’ means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement and the Transition PPA in their respective entirety, including payments to be made by Party B, subject to CPUC review of Party B’s administration of each of the Agreement and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and nonappealable.” “1.63 ‘FERC Approval’ means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.7(a) of this Agreement in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal.” “1.64 ‘Fitch’ means Fitch Ratings Ltd. or its successor.” “1.65 ‘Forward Price Assessments’ means quotations solicited or obtained in good faith from regularly published and widely-distributed forward price assessments from a broker that is not an Affiliate of either Party and who is actively participating in markets for the relevant Products.” “1.631.66 ‘Market Quotation Average Price’ means the arithmetic mean of the quotations solicited in good faith from not less than three (3) Reference MarketMakers (as hereinafter defined); provided, however, that the Party obtaining the quotes shall use reasonable efforts to obtain good faith quotations from at least five (5) Reference Market-Makers and, if at least five (5) such quotations are obtained, the Market Quotation Average Price shall be determined by disregarding the highest and lowest quotations and taking the arithmetic mean of the remaining quotations. The quotations shall be based on the offers to sell or bids to buy, as applicable, obtained for transactions substantially similar to each Terminated Transaction. The quote must be obtained assuming that the Party obtaining the quote will provide sufficient credit support for the proposed transaction. Each quotation shall be obtained in good faith by such Party, to the extent reasonably practicable, as of the same day and time (without regard to different time zones) on or as soon as reasonably practicable after the relevant Early Termination Date, such day and time as of which those quotations will be selected shall be specified in accordance with Section 5.2. If fewer than three (3) quotations are obtained, it will be deemed that the Market Quotation Average Price in respect of such Terminated Transaction or group of Terminated Transactions cannot be determined.” “1.641.67 ‘Merger Event’ means, with respect to a Party or its Guarantor, that

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such Party or its Guarantor consolidates or amalgamates with, merges into or with, or transfers substantially all its assets to another entity and (i) the resulting entity fails to assume all the obligations of such Party hereunder or of such Party’s Guarantor under its guaranty, or (ii) the benefits of any credit support provided by such Party pursuant to Article Eight, or any guaranty provided by such Party’s Guarantor, fail to extend the performance by such resulting, surviving or transferee entity of its obligations hereunder, or (iii) the resulting entity’s creditworthiness is materially weaker than that of such Party or its Guarantor immediately prior to such action. The creditworthiness of the resulting entity shall not be deemed to be ‘materially weaker’ so long as the resulting entity maintains a Credit Rating of at least that of the applicable Party or its Guarantor, as the case may be, immediately prior to the consolidation, merger or transfer.” “1.651.68 ‘Ratings Agency’ means any of S&P, Moody’s, and Fitch, and any other ratings agency agreed by the Parties as set forth in the Cover Sheet of the Transition Master Agreement (collectively the ‘Ratings Agencies’).” “1.661.69 ‘Reference Market-Maker’ means a leading dealer in the relevant market that is not an Affiliate of either Party and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker.” “1.671.70 ‘Specified Energy Transaction’ means the Transition PPA or any transaction (including an agreement with respect to any such transaction) now existing or hereafter entered into between Party A and Party B (or any Guarantor of such Party) which is not a Transaction under this Agreement, but which is a transaction under the International Swaps and Derivatives Association Master Agreement, the North American Energy Standards Board Base Contract for Purchase and Sale of Natural Gas, the WSPP Agreement, or under any other agreement with respect to the purchase, sale, or transfer of (a) wholesale physical electric energy or capacity; (b) wholesale physical natural gas; or (c) financial derivative products related thereto.” “1.68 ‘Fitch’ means Fitch Ratings Ltd. or its successor.”1.71 Collateral Annex’ has the meaning set forth in Section 5.1(e).”

‘Transition

“1.72 ‘Transition PPA’ means that certain Power Purchase and Sale Agreement, dated October 15, 2012, between Party A and Party B, as may be amended from time to time.”

ARTICLE TWO: TRANSACTION TERMS AND CONDITIONS. Amend Article Two as follows: Section 2.1 is amended by adding the following sentence to the end thereof “Any Transaction formed and effectuated pursuant to the foregoing shall be considered a ‘writing’ or ‘in writing’ and to have been ‘signed’ by each Party or otherwise binding on the Parties.” Section 2.2 is amended to delete the second comma after the words “supplements hereto),” and before “the Party” in the second sentence. Section 2.4 is amended by (i) deleting the words “either orally or” after the phrase

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“Section 2.3 unless agreed to” in the second to last line thereof. Section 2.5 is amended (i) to delete the phrase “Unless a Party expressly objects to a Recording (defined below) at the beginning of a telephone conversation,”; (ii) by capitalizing the word “each” in the first sentence; and (iii) replacing the words “Parties to this Master Agreement” with “Parties’ trading and marketing personnel”. A new Section 2.6 is added to read as follows: “2.6 Imaged Agreement. Any original executed Transition Master Agreement, Confirmation or other related document may be photocopied and stored on computer tapes and disks (the ‘Imaged Agreement’). The Imaged Agreement, if introduced as evidence on paper, the Confirmation, if introduced as evidence in automated facsimile form, the Recording, if introduced as evidence in its original form and as transcribed onto paper or into other written format, and all computer records of the foregoing, if introduced as evidence in printed format, in any judicial, arbitration, mediation or administrative proceedings, will be admissible as between the Parties to the same extent and under the same conditions as other business records originated and maintained in documentary form. Neither Party shall object to the admissibility of the Recording, the Confirmation, or the Imaged Agreement (or photocopies of the transcription of the Recording, the Confirmation, or the Imaged Agreement) on the basis that such were not originated or maintained in documentary or written form under either the hearsay rule or the best evidence rule. However, nothing in this Section 2.6 shall preclude a Party from challenging the admissibility of such evidence on some other grounds, including, without limitation, the basis that such evidence has been materially or substantially altered from the original.” A new Section 2.7 is added to read as follows: “2.7 Conditions Precedent.

(a) Within sixty (60) days of the Effective Date, Party B and Party A shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Party A nor Party B shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Party A the authority to sell the Product to Party B at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within thirty (30) calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Party B shall make best efforts to provide Party A with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within fifty (50) days after the Effective Date; provided that if Party B is unable to provide Party A with a draft of the public version of such independent evaluator report within 50 days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Party B provides

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Party A such independent evaluator report.

(b) Within sixty (60) days after the Effective Date, Party B shall file with the CPUC the appropriate request for CPUC Approval. Party B shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Party A shall use reasonable efforts to support Party B in obtaining CPUC Approval. Party B has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(c) Notwithstanding Party A’s and Party B’s execution and delivery of this Agreement, no Transaction under this Agreement will be permitted or deemed valid until the Parties obtain FERC Approval and Party B obtains CPUC Approval.

(d) Notwithstanding anything to the contrary set forth in this Agreement, no Transaction under this Agreement will be permitted or deemed valid until all of the condition precedents set forth in the Transition PPA have been satisfied or waived in accordance with the terms of the Transition PPA.” A new Section 2.8 is added to read as follows: “2.8 Termination Rights of the Parties; Automatic Termination.

(a) If the Transition PPA is terminated before the commencement of the Term Start Date of the Transition PPA (including if such termination is due to the inability to obtain FERC Approval or CPUC Approval), then this Agreement (including any Transaction and related Confirmation entered into between Party A and Party B as of the Effective Date) will automatically terminate on the date of the termination of the Transition PPA.” ARTICLE THREE: OBLIGATIONS AND DELIVERIES. Amend Article Three as follows: A new Section 3.4 is added to read as follows: “3.4 Index Transactions. If the Contract Price for a Transaction is determined by reference to an index, then the following provisions shall be applicable to such Transaction. (a)

Market Disruption. If a Market Disruption Event occurs during a Determination Period, the Floating Price for the affected Trading Day(s) shall be determined by reference to the Floating Price specified in the Transaction for the first Trading Day thereafter on which no Market Disruption Event exists; provided, however, if the Floating Price is not so determined within three (3) Business Days after the first Trading Day on which the Market Disruption Event occurred or existed, then the Parties shall negotiate in good faith to agree on a Floating Price (or a method for determining a Floating Price), and if the Parties have not so agreed on or before the twelfth Business Day following the first Trading Day on which the Market Disruption Event occurred or existed, then the Floating Price shall be determined in good faith by taking the average of the price quotations for the relevant commodity and relevant Business Days that are

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obtained from no more than two (2) Reference Market-Makers selected by each Party. (b) For purposes of this Section 3.4, the following definitions shall apply: (i) ‘Determination Period’ means each calendar month a part or all of which is within the Delivery Period of a Transaction. (ii) ‘Exchange’ means, in respect of a Transaction, the exchange or principal trading market specified in the relevant Transaction. (iii) ‘Floating Price’ means a price per unit in $U.S. specified in a Transaction that is based upon a Price Source. (iv) ‘Market Disruption Event’ means, with respect to any Price Source, any of the following events: (a) the failure of the Price Source to announce or publish the specified Floating Price or information necessary for determining the Floating price; (b) the failure of trading to commence or the permanent discontinuation or material suspension of trading in the relevant options contract or commodity on the Exchange or in the market specified for determining a Floating Price; (c) the temporary or permanent discontinuance or unavailability of the Price Source; (d) the temporary or permanent closing of any Exchange specified for determining a Floating Price; or (e) a material change in the formula for or the method of determining the Floating Price. (v) ‘Price Source’ means, in respect of a Transaction, the publication (or such other origin of reference, including an Exchange) containing (or reporting) the specified price (or prices from which the specified price is calculated) specified in the relevant Transaction. (vi) ‘Trading Day’ means a day in respect of which the relevant Price Source published the Floating Price. (c) Corrections to Published Prices. For purposes of determining a Floating Price for any day, if the price published or announced on a given day and used or to be used to determine a relevant price is subsequently corrected and the correction is published or announced by the person responsible for that publication or announcement within twelve (12) months of the original publication or announcement, either Party may notify the other Party of (i) that correction and (ii) the amount (if any) that is payable as a result of that correction. If, not later than thirty (30) days after publication or announcement of that correction, a Party gives notice that an amount is so payable, the Party that originally either received or retained such amount will, not later than ten (10) Business Days after the effectiveness of that notice, pay, subject to any applicable conditions precedent, to the other Party that amount, together with interest at the Interest Rate for the period from and including the day on which payment originally was (or was not) made to but excluding the day of payment of the refund or payment resulting from that correction. (d) Calculation of Floating Price. For the purposes of the calculation of a Floating Price, all numbers shall be rounded to three (3) decimal places. If the fourth (4th) decimal number is five (5) or greater, then the third (3rd) decimal number shall be increased by one (1), and if the fourth (4th) decimal number is less than five (5), then the third (3rd) decimal number shall remain

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unchanged.” ARTICLE FIVE: EVENTS OF DEFAULT; REMEDIES. Amend Article Five as follows: Section 5.1(a) is amended by replacing “three (3) Business Days” with “five (5) Business Days”. Section 5.1(e) is amended by adding after the word “hereof” the phrase “or any other credit arrangement, including, but not limited to, the Collateral Annex (the ‘Transition Collateral Annex’) (or any similar agreement) related to this Agreement”. Section 5.1(f) is amended to read as follows: “(f) a Merger Event occurs with respect to such Party or its Guarantor, if applicable;” Section 5.1(h)(iv) is amended by inserting the words “made in connection with this Agreement” after the first instance of the word “guaranty”. Section 5.1(h)(v) is amended by inserting the words “made in connection with this Agreement” after the word “guaranty”. Section 5.1 is amended by adding the following Sections 5.1(i) and 5.1(j) at the end thereof: “(i) an event of default occurs (howsoever determined) under a Specified Energy Transaction (including under the Transition PPA) with respect to such Party and, after giving effect to any applicable notice requirement or grace period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that Specified Energy Transaction; or (j) the Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, this Transition Master Agreement, any Confirmation executed and delivered by that Party, the Transition PPA or any Transaction evidenced by such a Confirmation.” Section 5.2 is amended by (i) inserting “(a)” at the beginning thereof; (ii) reversing the placement of “(i)” and “to”; (iii) inserting after the words “designate a day” the words “and time of day” in clause (i) thereof; (iv) replacing the phrase “as soon thereafter as is reasonably practicable)” with “, then each such Transaction — individually, an ‘Excluded Transaction’ and collectively, the ‘Excluded Transactions’— shall be terminated as soon thereafter as is reasonably practicable, and upon termination shall be deemed to be a Terminated Transaction) and the Termination Payment payable in connection with all Terminated Transactions shall be calculated in accordance with this Section 5.2 and with Section 5.3 below”; and (v) adding the following paragraph at the end thereof: “(b) The Non-Defaulting Party shall determine its Gains and Losses by determining the Market Quotation Average Price for each Terminated Transaction. In the event the Non-Defaulting Party is not able, after commercially reasonable efforts, to obtain the Market Quotation Average Price with respect to any Terminated Transaction, then the NonDefaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner by calculating the arithmetic mean of at least three (3) Forward Price Assessments for transactions substantially similar to each Terminated Transaction. In the

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event the Non-Defaulting Party is not able, after commercially reasonable efforts to obtain at least three (3) Forward Price Assessments with respect to any Terminated Transaction, then the Non-Defaulting Party shall calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner by reference to information supplied to it by one or more third parties including, without limitation, index prices, quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads, or other relevant market data in the relevant markets; provided, however, that the provider of such information shall not be an Affiliate of either Party. Only in the event the Non-Defaulting Party is not able, after using commercially reasonable efforts, to obtain such third party information, then the Non-Defaulting Party may calculate its Gains and Losses for such Terminated Transaction in a commercially reasonable manner using relevant market data it has available to it internally.” Section 5.3 is amended by (i) deleting the “:” in the second line thereof; (ii) replacing the words “Agreement against” with “Agreement, against” immediately before “(b)”; and (iii) inserting the phrase “any cash then available to the Defaulting Party pursuant to Article Eight,” between the words “Non-Defaulting Party,” and “plus any” in the sixth line thereof. Section 5.4 is amended by inserting the phrase “but in no event more than fifteen (15) Business Days following the Early Termination Date,” after the phrase “liquidation,” in the second line thereof. Section 5.6 Option A is amended by (i) inserting the following phrase “with respect to the Specified Energy Transactions,” before the words “and/or (ii)” and (ii) adding the following at the end thereof : “Notwithstanding anything to the contrary contained in this Transition Master Agreement, or in any other agreement, instrument, or undertaking between the Parties with respect to a Specified Energy Transaction, if an Early Termination Date has been designated pursuant to Section 5.2, then, in addition to the other remedies provided in this Transition Master Agreement, the Non-Defaulting Party may accelerate, liquidate and terminate all, but not less than all, Specified Energy Transactions between the Parties.” Section 5.7 is amended to capitalize the word “early” in line 6 to read “Early”. ARTICLE SIX: PAYMENT AND NETTING. Amend Article Six as follows: Section 6.3 is amended to read as follows: “6.3 Disputes and Adjustments of Invoices. A Party may adjust any invoice rendered by it under this Agreement to correct any arithmetic or computational error or to include additional charges or claims within twenty-four (24) months after the close of the month in which the obligations being invoiced arose. A receiving Party may, in good faith, dispute the correctness of any invoice or of any adjustment to any invoice previously rendered to it by providing notice to the other Party on or before the later of (i) twelve (12) months of the date of receipt of such invoice or adjusted invoice, or (ii) twenty-four (24) months after the close of the month in which the obligation being invoiced arose. Failure to provide such notice within the time frame set forth in the preceding sentence waives the dispute with respect to such invoice. A Party disputing all or any part of an invoice or an adjustment to an invoice previously rendered to it may pay

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only the undisputed portion of the invoice when due, provided such Party provides notice to the other Party of the basis for and amount of the disputed portion of the invoice that has not been paid. The disputed portion of the invoice must be paid within two (2) Business Days of resolution of the dispute, along with interest accrued at the Interest Rate from and including the original due date of the invoice to but excluding the date the disputed portion of the invoice is actually paid. Inadvertent overpayments shall be returned upon request or deducted by the Party receiving such overpayment from subsequent payments, with interest accrued at the Interest Rate from and including the date of such overpayment but excluding the date repaid or deducted by the Party receiving such overpayment. An invoice can only be adjusted or amended after it was originally rendered within the twenty-four (24) month time framesframe set forth in the first sentence of this Section 6.3. If an invoice is not rendered within twenty-four (24) months after the close of the month in which the payment obligations arose, the right to payment for that month under this Agreement is waived.” Section 6.7 is amended to replace the phrase “Section 6.1” with the phrase “Section 6.2”. ARTICLE SEVEN: LIMITATIONS. Amend Article Seven as follows: Section 7.1 is amended to (i) delete the phrase “EXCEPT AS SET FORTH HEREIN” in the first sentence; and (ii) in the fifth sentence (a) replace in its entirety the phrase “UNLESS EXPRESSLY HEREIN PROVIDED” with “NOTWITHSTANDING ANYTHING IN THIS AGREEMENT TO THE CONTRARY”; (b) add the following phrase “SET FORTH IN THIS AGREEMENT” after the words “INDEMNITY PROVISION”; and (c) add the following phrase “; PROVIDED, HOWEVER, THAT NOTHING IN THIS PROVISION SHALL AFFECT THE ENFORCEABILITY OF SECTIONS 5.2 AND 5.3 OF THIS AGREEMENT” after the words “OR OTHERWISE”. ARTICLE EIGHT: CREDIT AND COLLATERAL REQUIREMENTS. Amend Article Eight as follows: Section 8.1(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes) after the words “consolidated financial statements” in the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations, provided however, for the purposes of this (i) and (ii), if Party B’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party B’s website, then Party B shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line. [SCE comment—The following is applicable if Option A is selected] Section 8.2(a) Option A is amended to add (i) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes)” after the words “consolidated financial statements” in

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the third line; (ii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; and (iii) the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year [if Party A is an SEC reporting company: certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations] [OR if Party A is not an SEC reporting company: certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year end audit adjustments)], provided however, for the purposes of this (i) and (ii), if Party A’s financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party A’s website, then Party A shall be deemed to have met this requirement” after the words “for such fiscal quarter” in the fifth line; and (v) at the end thereof the phrase “[if Party A is not an SEC reporting company: For purposes of this Section, ‘Responsible Officer’ shall mean the Chief Financial OfficerExecutive Director, Treasurer or any Assistant Treasurer of Party A or any employee of Party A designated by any of the foregoing.]”. [SCE comment—The following is applicable if Option B is selected] Section 8.2(a) Option B is amended to add (i) the phrase “or Party A’s Guarantor [or other entity specified on the Cover Sheet]” after the words “Party A” in the first line; (ii) the following phrase “(income statement, balance sheet, statement of cash flows and statement of retained earnings and all accompanying notes)” after the words “consolidated financial statements” in the third line; (iii) the phrase “setting forth in each case in comparative form the figures for the previous year” after the words “for such fiscal year,” in the third line; (iv) is amended by replacing the phrase “for the party(s) specified on the Cover Sheet” with the phrase “and the portion of the fiscal year through the end of such quarter, setting forth in each case in comparative form the figures for the previous year [if Party A’s Guarantor [or other entity specified on the Cover Sheet] is an SEC reporting company: certified in accordance with all applicable laws and regulations, including without limitation all applicable Securities and Exchange Commission rules and regulations] [OR if Party A’s Guarantor [or other entity specified on the Cover Sheet]is not an SEC reporting company: certified by a Responsible Officer as being fairly stated in all material respects (subject to normal year end audit adjustments)], provided however, for the purposes of this (i) and (ii), if Party A’s Guarantor’s [or other entity specified on the Cover Sheet] financial statements are publicly available electronically on the Securities and Exchange Commission’s website or Party A’s Guarantor’s [or other entity specified on the Cover Sheet] website, then this requirement shall be deemed satisfied” in the fifth line; and (v) at the end thereof the phrase “[if Party A’s Guarantor [or other entity specified on the Cover Sheet] is not an SEC reporting company: For purposes of this Section, ‘Responsible Officer’ shall mean the Chief Financial Officer, Treasurer or any Assistant Treasurer of Party A’s Guarantor or any employee of Party A’s Guarantor designated by any of the foregoing.]”. A new Section 8.4 is added to read as follows: “8.4 [Uniform/California] Commercial Code Waiver. This Agreement and the Transition Collateral Annex set forth the entirety of the agreement of the Parties regarding credit, collateral and adequate assurances, in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement. Except as expressly set forth in the options elected by the Parties in respect of Sections 8.1 and 8.2, in Section 8.3, and in the relevant

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portions of the Transition Collateral Annex, neither Party: (a) has or will have any obligation to post margin, provide letters of credit, pay deposits, make any other prepayments or provide any other financial assurances, in any form whatsoever, or (b) will have reasonable grounds for insecurity with respect to the creditworthiness of a Party that is complying with the relevant provisions of Section 8 of this Transition Master Agreement and of the relevant provisions of the Transition Collateral Annex; in each case, with respect to the Transition Master Agreement and the Transactions under the Transition Master Agreement, and all implied rights relating to financial assurances arising from Section 2-609 of the [Uniform/California] Commercial Code Section 2609 or case law applying similar doctrines, are hereby waived.” ARTICLE NINE: GOVERNMENTAL CHARGES. Amend Article Nine as follows: Section 9.2, is amended to add the words “, charges, or fees” after the word “taxes” in the first line thereof. ARTICLE TEN: MISCELLANEOUS. Amend Article Ten as follows: Section 10.2(vi) is amended to add the phrase “(for purposes of this Section 10.2(vi), Party B shall be deemed to have no Affiliates)” after the word “Affiliates”. Section 10.2(x) is amended to read as follows: “(x) it is an ‘eligible commercial entity’ within the meaning of Section 1a (11) of the Commodity Exchange Act, as amended by the Commodity Futures Modernization Act of 2000 (the ‘Commodity Exchange Act’);” Section 10.2(xi) is amended to read as follows: “(xi) it is an ‘eligible contract participant’ within the meaning of Section 1a (12) of the Commodity Exchange Act; and ” Section 10.2(xii) is amended to read as follows: “(xii) each Transaction that is not executed or traded on a ‘trading facility’, as defined in Section 1(a)(33) of the Commodity Exchange Act, is subject to individual negotiation by the Parties.” Section 10.4 is amended by adding the following sentence at the end thereof: “Neither Party shall be liable with respect to any Claim to the extent that such Claim resulted from the negligence, willful misconduct, or bad faith of the indemnified Party.” Section 10.5 is amended as follows: (a) add the following phrase to the end of clause (i) immediately after the word “arrangements” the phrase “to any person or entity whose creditworthiness is equal to or higher than that of such Party”; (b) in clause (ii) replace the words “affiliate” and “affiliate’s” with, respectively “Affiliate” and “Affiliate’s”; and (c) in clause (iii) immediately after the words “substantially all of the assets” insert the words “of such Party and”.

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Section 10.6 is amended to read as follows: “10.6 Governing Law; Venue; Dispute Resolution. (a) Governing Law and Venue:. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAWS. EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY DISPUTE ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT. The Parties hereby consent to conduct all dispute resolution, judicial actions or proceedings arising directly, indirectly or otherwise in conjunction with, out of, related to, or arising from this Agreement in Los Angeles County, California. (b) Dispute Resolution: (i) Mediation. The Parties agree that any. Any and all disputes, claimsClaims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which disputes, claims, or controversiesDisputes the Parties have been unable to resolve by informal methods after undertaking a good faith effort to do so, shall, will first be submitted to Judicial Arbitration and Mediation Services, Inc. (‘JAMS’), its successor, or any other mutually agreeable neutral (the ‘Mediator’) for mediation in accordance with the procedures described in Section 10.6(c), and if the matterDispute is not resolved through mediation, then it shall be submitted as provided below for final and binding arbitration in accordance with the procedures described in Section 10.6(d). (c) Mediation. Either Party may initiate the mediation by providing notice to the other Party of a written request for mediation, setting forth the subjecta description of the disputeDispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the JAMS’ panel of neutrals, or in selecting a from the Judicial Arbitration and Mediation Services, Inc. or any successor entity (“JAMS”), or any other mutually acceptable non-JAMS Mediator, and such proceedings shall be conducted in accordance with the laws of the State of California, without regards to principles of conflicts of laws. Such selection and scheduling will be completed within forty-five (45) days after notice of the request for mediation. Unless the Parties agree to a different arrangement, the place of the mediation shall be in Los Angeles County, California, . Unless otherwise agreed to by the Parties, however, the mediation shallwill not be scheduled for a date that is greater than one-hundred twenty (120) days from the date of notice of the initial written request for mediation. The Parties covenant that they will participate in the mediation in good faith, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and costs shallwill be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, shallwill not be subject to discovery and shallwill be confidential, privileged and inadmissible for any

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purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them,; provided, however, that evidence that is otherwise admissible or discoverable shallwill not be rendered inadmissible or non-discoverable as a result of its use in the mediation. (iid) Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation by making a writtenin accordance with Section 10.6(c) by providing notice of a demand for binding arbitration before a single, neutral arbitrator (the ‘“Arbitrator’”) at any time following the earlier of (a) 150 days from the initial request for mediation provided above, or (b) the unsuccessful conclusion of the mediation provided for in Section 10.6(c). The Parties will cooperate with one another in promptly selecting the Arbitrator and shallwithin sixty (60) days after notice of the demand for arbitration and will further cooperate in scheduling the arbitration hearing to commence no later than one-hundred eighty (180) days from the date of notice of the initial written demand for binding arbitration. If, notwithstanding their good faith efforts,. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator shallwill be appointed as provided for in California Code of Civil Procedure Section 1281.6.1281.6, in which case each candidate for Arbitrator must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator shallwill be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon notice of a Party’s written demand for binding arbitration, such dispute, claim or controversyDispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, shallwill be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regardsregard to principles of conflicts of laws. Except as provided for hereinin this Section 10.6(d), the arbitration shallwill be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated; absent. Absent the existence of such rules and procedures, the arbitration shallwill be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). However, notwithstanding Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration shallwill be in Los Angeles County, California, each side in the arbitration shall be entitled to take up to three (3) depositions, and all direct testimony in the arbitration shall be submitted, California, and discovery will be limited as follows: (i) before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment); (ii) the initial disclosure will occur within thirty (30) days after the initial conference with the Arbitrator or at such time as the Arbitrator may order;

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(iii) discovery may commence at any time after the Parties’ initial disclosure; (iv) the Parties will not be permitted to propound any interrogatories or requests for admissions; (v) discovery will be limited to twenty-five (25) document requests (with no subparts), three (3) lay witness depositions, and three (3) expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents); (vi) each Party is allowed a maximum of three (3) expert witnesses, excluding rebuttal experts; (vii) Within sixty (60) days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding; (viii) within thirty (30) days after the initial expert disclosure, the Parties may designate a maximum of two (2) rebuttal experts; (ix) unless the Parties agree otherwise, all direct testimony will be in the form of affidavits or declarations under penalty of perjury. Each; and (x) each Party shall cooperate in makingmake available for cross-examination at the arbitration hearing its witnesses whose direct testimony has been so submitted. The Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections3.01, 3.02, 3.03, 9.09 of the Transition PPA. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator shallmust, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs shallwill be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail. Until such award is made, however, the Parties shallwill share equally in paying the costs of the arbitration. At the conclusion of the arbitration hearing, the Arbitrator shall prepare in writing and provide to each Party a decision setting forth factual findings, legal analysis, and the reasons on which the Arbitrator’s decision is based. The Arbitrator shall also have the authority to resolve claims or issues in advance of the arbitration hearing that would be appropriate for a California superior court judge to resolve in advance of trial. The Arbitrator shall not have the power to commit errors of law or fact, or to commit any abuse of discretion, that would constitute reversible error had the decision been rendered by a California superior court. The Arbitrator’s decision may be vacated or corrected on appeal to a California court of competent jurisdiction for such error. Unless otherwise agreed to by the Parties, all proceedings before the Arbitrator shall be reported and transcribed by a certified court reporter, with each Party bearing one-half of the court reporter’s fees.” Section 10.8 is amended to replace in the penultimate sentence thereof the phrase “twelve (12) months” with the phrase “two (2) years”.

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Section 10.10 is amended to read as follows: “10.10 Bankruptcy Issues. The Parties intend that (i) all Transactions constitute a ‘forward contract’ within the meaning of the United States Bankruptcy Code (the ‘Bankruptcy Code’) or a ‘swap agreement’ within the meaning of the Bankruptcy Code; (ii) all payments made or to be made by one Party to the other Party pursuant to this Agreement constitute ‘settlement payments’ within the meaning of the Bankruptcy Code; (iii) all transfers of Performance Assurance by one Party to the other Party under this Agreement constitute ‘margin payments’ within the meaning of the Bankruptcy Code and (iv) this Agreement constitutes a ‘master netting agreement’ within the meaning of the Bankruptcy Code. Each Party further agrees that, for purposes of this Agreement, the other Party is not a ‘utility’ as such term is used in 11 U.S.C. Section 366, and each Party waives and agrees not to assert the applicability of the provisions of 11 U.S.C. Section 366 in any bankruptcy proceeding wherein such Party is a debtor. In any such proceeding, each Party further waives the right to assert that the other Party is a provider of last resort to the extent such term relates to 11 U.S.C. Section 366 or another provision of 11 U.S.C. Section 101-1532.” Section 10.11 is amended to read as follows: “10.11 Confidentiality. If the Parties have elected on the Cover Sheet of the Transition Master Agreement to make this Section 10.11 applicable to this Transition Master Agreement, neither Party shall disclose the terms or conditions of this Agreement to a third party (other than the Party’s or the Party’s Affiliates’ officers, directors, employees, lenders, counsel, accountants, advisors, or rating agencies who have a need to know such information and have agreed to keep such terms confidential) except (i) in order to comply with any applicable law, order, regulation, ruling, summons, subpoena, exchange rule, or accounting disclosure rule or standard, or to make any showing required by any applicable governmental authority; (ii) to the extent necessary for the enforcement of this Agreement or to implement any Transaction; (iii) as may be obtained from a non-confidential source that disclosed such information in a manner that did not violate its obligations to the non-disclosing Party or its Guarantor in making such disclosure; (iv) to the extent such disclosure to a third party is for the sole purpose of calculating a published index, so long as such third party (1) has agreed prior to the disclosure to protect the specific information disclosed from public disclosure and (2) is a party engaged in the business of collecting such information for the purpose of establishing, creating, or formulating a published index; (v) to the extent such information is or becomes generally available to the public prior to such disclosure by a Party; (vi) when required to be released in connection with any regulatory proceeding (provided that the releasing Party makes reasonable efforts to obtain confidential treatment of the information being released); or (vii) with respect to Party B, as may be furnished to its duly authorized regulatory and governmental agencies or entities, including without limitation the California Public Utilities Commission (the “CPUC”) and all divisions thereof, and to Party B’s Procurement Review Group (the “PRG”), a group of participants including members of the CPUC and other governmental agencies and consumer groups established by the CPUC in D.02-08-071 and D.03-06-071. The existence of this Agreement is not subject to this confidentiality obligation; provided that neither Party shall make any public announcement relating to this Agreement unless required pursuant to subsection (i) or (vi) of the foregoing sentence of this Section 10.11. The Parties shall be entitled to all remedies available at law or in equity to enforce, or seek relief in

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connection with, this confidentiality obligation. With respect to information provided in connection with a Transaction, this obligation shall survive for a period of three (3) years following the expiration or termination of such Transaction. With respect to information provided under this Agreement, this obligation shall survive for a period of three (3) years following the expiration or termination of this Agreement. For the purposes of this Section 10.11, “Affiliate” for Party A shall mean __________Chevron Corporation, Chevron U.S.A. Inc., Chevron Sycamore Cogeneration Company, Western Sierra Energy Company and Edison Mission Energy and “Affiliate” for Party B shall mean Edison International; provided, however, that for Party A, "Affiliate" shall

not apply to the power marketing or trading personnel of Chevron Corporation, Chevron U.S.A. Inc., Chevron Sycamore Cogeneration Company, Western Sierra Energy Company or Edison Mission Energy.” New Sections 10.12 and 10.13 shall be added as follows: “10.12 No Agency. In performing their respective obligations hereunder, neither Party is acting, or is authorized to act, as agent of the other Party.” “10.13 Mobile Sierra Doctrine. (a) Absent the agreement of all Parties to the proposed change, the standard of review for changes to any rate, charge, classification, term or condition of this Agreement, whether proposed by a Party (to the extent that any waiver in subsection (b) below is unenforceable or ineffective as to such Party), a non-party or FERC acting sua sponte, shall be the ‘public interest’ standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S. 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956) (the ‘Mobile Sierra’ doctrine). (b) Notwithstanding any provision of Agreement, and absent the prior written agreement of the Parties, each Party, to the fullest extent permitted by Applicable Laws, for itself and its respective successors and assigns, hereby also expressly and irrevocably waives any rights it can or may have, now or in the future, whether under Sections 205, 206, or 306 of the Federal Power Act or otherwise, to seek to obtain from FERC by any means, directly or indirectly (through complaint, investigation, supporting a third party seeking to obtain or otherwise), and each hereby covenants and agrees not at any time to seek to so obtain, an order from FERC changing any Section of this Agreement specifying any rate or other material economic terms and conditions agreed to by the Parties.” SCHEDULE P: PRODUCTS AND DEFINITIONS. Amend Schedule P as follows: The following definitions are added: “ ‘CAISO Energy’ means with respect to a Transaction, a Product under which the Seller shall sell and the Buyer shall purchase a quantity of energy equal to the hourly quantity without Ancillary Services (as defined in the Tariff) that is or will be scheduled as a schedule coordinator to schedule coordinator transaction pursuant to the applicable tariff and protocol provisions of the CAISO (as amended from time to time, the ‘Tariff’) for which the only excuse for failure to deliver or receive is an Uncontrollable Force (as defined in the Tariff).”

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The following products are added: “Other Products and Service Levels. If the Parties agree to a service level or product defined by a different agreement, set of rules, tariff, or protocol (herein, the ‘agreement’) (i.e., the WSPP Agreement) for a particular Transaction, then, unless the Parties expressly state and agree that all the terms and conditions of such other agreement will apply, such reference to a service level or product defined by such other agreement means that the service level or product for that Transaction is subject to the applicable regional independent system operator and/or utility reliability requirements and guidelines as well as the permitted excuses for performance, Force Majeure, Uncontrollable Forces, or other such excuses applicable to performance under such other agreement, to the extent inconsistent with the terms of this Agreement, provided, however, that all other terms and conditions of this Agreement shall and do remain applicable including, without limitation, Section 2.2; and provided, further that with respect to any Transaction for a product or service level defined by such other agreement, the methodology for calculating the payments for failure to deliver or receive shall be in accordance with Sections 4.1 and 4.2 of the Transition Master Agreement; provided, further that the ‘Accelerated Payment of Damages’ addressed in Article Four and agreed to in the Cover Sheet of the Transition Master Agreement shall continue to apply.” “Into __________ (the ‘Receiving Transmission Provider’), Seller’s Daily Choice” is deleted in its entirety.

IN WITNESS WHEREOF, the Parties have caused this Transition Master Agreement to be duly executed as of the date first above written. Party A: SYCAMORE COGENERATION COMPANY

Party B: SOUTHERN CALIFORNIA EDISON COMPANY

By:

By:

Name: Neil Burgess

Name: Marc L. Ulrich

Title:

Title:

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

DISCLAIMER: This Master Power Purchase and Sale Agreement was prepared by a committee of representatives of Edison Electric Institute (“EEI”) and National Energy Marketers Association (“NEM”) member companies to facilitate orderly trading in and development of wholesale power markets. Neither EEI nor NEM nor any member company nor any of their agents, representatives or attorneys shall be responsible for its use, or any damages resulting there from. By providing this Agreement EEI and NEM do not offer legal advice and all users are urged to consult their own legal counsel to ensure that their commercial objectives will be achieved and their legal interests are adequately protected.

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SCHEDULE 1 – Form of Letter of Credit ISSUE DATE: L/C NO.: __________________ ACCOUNT PARTY: ACCOUNT NAME ADDRESS CITY, STATE XXXXX-XXXX BENEFICIARY NAME ADDRESS CITY, STATE XXXXX-XXXX

AMOUNT: USD XXXX.00 (XXX AND 00/100 UNITED STATES DOLLARS)

WE HEREBY ESTABLISH THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT NO. ______________ FOR AN AGGREGATE AMOUNT NOT TO EXCEED THE AMOUNT INDICATED ABOVE, EXPIRING AT OUR COUNTERS WITH OUR CLOSE OF BUSINESS ON (DATE). THIS LETTER OF CREDIT IS AVAILABLE WITH (BANK NAME), AGAINST PRESENTATION OF YOUR DRAFT AT SIGHT DRAWN ON (BANK NAME), WHEN ACCOMPANIED BY:

1) THE ORIGINAL OF THIS LETTER OF CREDIT (OR A PHOTOCOPY OF THE ORIGINAL FOR PARTIAL DRAWINGS) AND ANY SUBSEQUENT AMENDMENTS, IF ANY; AND

2) A DRAW CERTIFICATE (SEE EXHIBIT A) PURPORTEDLY SIGNED BY ONE OF THE BENEFICIARY’S OFFICIALSREPRESENTATIVES. BENEFICIARY SHALL BE ENTITLED TO DRAW UPON THIS LETTER OF CREDIT UP TO THE STATED AMOUNT, IN ONE OR MORE DRAWINGS; PROVIDED HOWEVER, THAT IF ANY DRAWING WOULD EXCEED THE STATED AMOUNT, BENEFICIARY SHALL BE ENTITLED TO DRAW ONLY THAT PORTION THAT WOULD NOT EXCEED THE STATED AMOUNT. ALL CORRESPONDENCE AND ANY DRAWINGS HEREUNDER ARE TO BE DIRECTED TO (BANK ADDRESS/CONTACT). WE HEREBY AGREE WITH YOU THAT DRAFTS DRAWN UNDER AND IN COMPLIANCE WITH THE TERMS AND CONDITIONS OF THIS LETTER OF CREDIT WILL BE DULY HONORED. THIS IRREVOCABLE NONTRANSFERABLE STANDBY LETTER OF CREDIT IS ISSUED SUBJECT TO THE INTERNATIONAL STANDBY PRACTICES 1998, INTERNATIONAL CHAMBER OF COMMERCE PUBLICATION NO. 590 (ISP98) AND AS TO MATTERS NOT ADDRESSED BY THE ISP98 THIS LETTER OF CREDIT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK, WITHOUT REGARD TO PRINCIPLES OF CONFLICT OF LAWS. THE NUMBER AND THE DATE OF OUR CREDIT AND THE NAME OF OUR BANK MUST BE QUOTED ON ALL DRAFTS REQUIRED.

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EEI Master Agreement Cover Sheet SCE version09.12.11

EXHIBIT A DRAW CERTIFICATE AN “EVENT OF DEFAULT” OR “EARLY TERMINATION DATE” (AS DEFINED IN SECTION 5 OF THE EDISON ELECTRIC INSTITUTE MASTER POWER PURCHASE & SALE AGREEMENT VERSION 2.1 AS MODIFIED ON 4/25/00 BETWEEN ACCOUNT PARTY AND BENEFICIARY, DATED _____________________ (THE “POWER PURCHASE AND SALE AGREEMENT”)) HAS OCCURRED AND IS CONTINUING WITH RESPECT TO THE ACCOUNT PARTY UNDER THIS LETTER OF CREDIT. WHEREFORE, THE UNDERSIGNED DOES HEREBY DEMAND PAYMENT TO THE UNDERSIGNED OF $USD (INSERT AMOUNT) BUT NOT TO EXCEED THE REMAINING UNDRAWN AMOUNT OF THE LETTER OF CREDIT. THE AMOUNT DEMANDED UNDER THIS LETTER OF CREDIT HAS BEEN COMPUTED IN ACCORDANCE WITH THE POWER PURCHASE AND SALE AGREEMENT. (COMPANY NAME)

By: (SIGNATURE OF COMPANY OFFICERREPRESENTATIVE) Title: _____________________________________

DATED: _________________________

24

Document comparison by Workshare Professional on Friday, October 12, 2012 4:21:00 PM Input: Document 1 ID Description

Document 2 ID

Description Rendering set

file://J:\RAP Contract Origination\2011 CHP\03_Issue Package\Attachment D-1 - EEI Master\Attachment D-1 EEI Master Cover Sheet Elections.doc Attachment D-1 - EEI Master Cover Sheet Elections file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\Transition Contract Applications\2801 & 2058 - KRCC & Sycamore\Subsequent PPAs\Sycamore Subsequent PPA\Internal Drafts\20121012\20121012 Sycamore Transition EEI.DOC 20121012 Sycamore Transition EEI standard

Legend: Insertion Deletion Moved from Moved to Style change Format change Moved deletion Inserted cell Deleted cell Moved cell Split/Merged cell Padding cell Statistics: Count Insertions Deletions Moved from Moved to Style change Format changed

175 101 2 2 0 0

Total changes

280

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between SOUTHERN CALIFORNIA EDISON COMPANY and [SELLER’S NAME] SYCAMORE COGENERATION COMPANY (RAP ID #[Number]2810)

Transition Standard Contract for Existing Qualifying Cogeneration Facilities

TERMS THAT ARE BOXED AND SHADED IN LIGHT YELLOW AND/OR BRACKETED AND IN BLUE FONT ARE EITHER SCE COMMENTS OR GENERATING FACILITY-TYPE SPECIFIC COMMENTS THAT SHOULD BE REMOVED, ACCEPTED OR COMPLETED, AS APPLICABLE.

The contents of this document are subject to restrictions on disclosure as set forth herein.

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

TABLE OF CONTENTS LIST OF EXHIBITS ....................................................................................................... iiiiv  PREAMBLE ........................................................................................................................1  RECITALS ..........................................................................................................................1  ARTICLE ONE:  SPECIAL CONDITIONS ................................................................3  1.01  Term ................................................................................................................3  1.02  Generating Facility..........................................................................................3  1.03  Delivery Point ...............................................................................................45  1.04  Capacity Performance Requirements ..............................................................5  1.05  Maintenance Outages; Major Overhaul ..........................................................5  1.06  Power Product Prices ......................................................................................5  1.07  [Intentionally omitted.] ...................................................................................6  1.08  Scheduling Coordinator Election ....................................................................6  ARTICLE TWO: SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION ......................................................7  2.01  Seller’s Satisfaction of Obligations before the Term Start Date.....................7  2.02  Termination Rights of the Parties ...................................................................8  2.03  Rights and Obligations Surviving Termination ..............................................9  2.04  CPUC Filing and Approval of this Agreement .............................................10  2.05  FERC Filing and Approval ...........................................................................10  2.06  Commencement of Term under Confirmations ............................................11  ARTICLE THREE:  SELLER’S OBLIGATIONS .....................................................1012  3.01  Conveyance of the Product; Retained Benefits ........................................1012  3.02  Resource Adequacy Rulings .....................................................................1113  3.03  Site Control ...............................................................................................1214  3.04  Permits ......................................................................................................1214  3.05  Transmission .............................................................................................1214  3.06  CAISO Relationship .................................................................................1315  3.07  Generating Facility Modifications ...........................................................1315  3.08  Metering ....................................................................................................1517  3.09  Telemetry System .....................................................................................1618  3.10  Provision of Information ...........................................................................1719  3.11  [Intentionally omitted.] .............................................................................1820  3.12  Fuel Supply ...............................................................................................1820  3.13  Demonstrations .........................................................................................1820  3.14  Operation and Record Keeping .................................................................1820  3.15  Power Product Curtailments at Transmission Provider’s or CAISO’s Request ......................................................................................................2022  3.16  Report of Lost Output ...............................................................................2123  3.17  FERC Qualifying Cogeneration Facility Status ........................................2224  3.18  Notice of Cessation or Termination of Service Agreements ....................2225  3.19  Buyer’s Access Rights ..............................................................................2325  3.20  Seller Financial Information .....................................................................2325  3.21  NERC Electric System Reliability Standards ...........................................2628  The contents of this document are subject to restrictions on disclosure as set forth herein. Table of Contents

i

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

3.22 

Allocation of Availability Incentive Payments and Non-Availability Charges .....................................................................................................2729  3.23  Seller’s Reporting Requirements .............................................................2730  ARTICLE FOUR:  BUYER’S OBLIGATIONS.......................................................2831  4.01  Obligation to Pay ......................................................................................2831  4.02  Payment Adjustments ...............................................................................2831  4.03  Payment Statement and Payment ..............................................................2932  4.04  GHG Compliance Costs............................................................................3135  4.05  No Representation by Buyer .....................................................................3135  4.06  Buyer’s Responsibility ..............................................................................3235  4.07  Buyer’s Reporting Requirements ..............................................................3235  ARTICLE FIVE:  FORCE MAJEURE ...................................................................3336  5.01  No Default for Force Majeure...................................................................3336  5.02  Requirements Applicable to the Claiming Party ......................................3336  5.03  Termination ...............................................................................................3336  ARTICLE SIX:  EVENTS OF DEFAULT; REMEDIES .....................................3437  6.01  Events of Default ......................................................................................3437  6.02  Early Termination .....................................................................................3740  6.03  Termination Payment ................................................................................3740  ARTICLE SEVEN:  LIMITATIONS OF LIABILITIES ............................................3842  ARTICLE EIGHT:  GOVERNMENTAL CHARGES...............................................4044  8.01  Cooperation to Minimize Tax Liabilities ..................................................4044  8.02  Governmental Charges..............................................................................4044  8.03  Providing Information to Taxing Governmental Authorities ...................4044  ARTICLE NINE:  MISCELLANEOUS ..................................................................4145  9.01  Representations and Warranties ................................................................4145  9.02  Additional Representations, Warranties, and Covenants by Seller ..........4246  9.03  Indemnity ..................................................................................................4246  9.04  Assignment ...............................................................................................4448  9.05  Consent to Collateral Assignment ............................................................4549  9.06  Governing Law and Jury Trial Waiver .....................................................4852  9.07  Notices ......................................................................................................4852  9.08  General ......................................................................................................4853  9.09  Confidentiality ..........................................................................................5054  9.10  Insurance ...................................................................................................5256  9.11  Nondedication ...........................................................................................5458  9.12  Mobile Sierra ............................................................................................5459  9.13  Seller Ownership and Control of Generating Facility ..............................5459  9.14  Simple Interest Payments ..........................................................................5559  9.15  Payments ...................................................................................................5559  9.16  Provisional Relief......................................................................................5559  ARTICLE TEN:  DISPUTE RESOLUTION .........................................................5661  10.01  Dispute Resolution ....................................................................................5661  10.02  Mediation ..................................................................................................5661  The contents of this document are subject to restrictions on disclosure as set forth herein. Table of Contents

ii

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

10.03  Arbitration .................................................................................................5661  SIGNATURES...............................................................................................................5964  

The contents of this document are subject to restrictions on disclosure as set forth herein. Table of Contents

iii

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

LIST OF EXHIBITS A.

Definitions

B.

Generating Facility and Site Description

C.

[Intentionally omitted]

D.

Monthly Contract Payment Calculation

D-1.

Force Majeure Credit Value

D-2.

Transmission Curtailment Credit Value

E.

Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

F.

[Intentionally omitted]

G.

Scheduling Coordinator Services

H.

[Intentionally omitted]

I.

Seller’s Forecasting Submittal and Accuracy Requirements

J.

CAISO Charges

K.

Scheduling and Delivery Deviation Adjustments

L.

Physical Trade Settlement Amount

M.

SC Trade Settlement Amount

N.

Notice List

O.

[Intentionally omitted]

P.

[Intentionally omitted]

Q.

[Intentionally omitted]

R.

Outage Schedule Submittal Requirements

S.

TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

T.

QF Efficiency Monitoring Program – Cogeneration Data Reporting Form

The contents of this document are subject to restrictions on disclosure as set forth herein. Table of Contents

iv

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

POWER PURCHASE AND SALE AGREEMENT between SOUTHERN CALIFORNIA EDISON COMPANY and [SELLER’S NAME] SYCAMORE COGENERATION COMPANY (RAP ID# [Number] #2810) PREAMBLE This Power Purchase and Sale Agreement by and between Southern California Edison Company, a California corporation (“Buyer”), and [Seller’s name], a [Seller’s form of business entity and state of registration]Sycamore Cogeneration Company, a California general partnership (“Seller”), together with the exhibits, attachments, and any applicable referenced collateral agreement or similar arrangement between the Parties that is expressly incorporated into this Agreement by the Parties (collectively, this “Agreement”), is made, effective and binding as of [Date of execution]October 15, 2012 (the “Effective Date”). Buyer and Seller are sometimes referred to in this Agreement individually as a “Party” and jointly as the “Parties.” Unless the context otherwise specifies or requires, initially capitalized terms used in this Agreement have the meanings set forth in Exhibit A. RECITALS A.

On or about September 20, 2007, the CPUC issued Decision (“D.”) 07-09-040 (the “Decision”) which, among other things, directed Buyer to develop a form of a standard contract and offer such contract to qualifying facilities meeting the eligibility criteria set forth in the Decision.

B.

Commencing in May 2009, Pacific Gas and Electric Company, San Diego Gas and Electric Company, Southern California Edison Company, the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, the Independent Energy Producers Association, the Division of Ratepayer Advocates of the California Public Utilities Commission, and The Utility Reform Network (collectively, the “Settling Parties”) entered into CPUC-facilitated settlement negotiations in order to resolve certain outstanding issues among the Settling Parties, including the implementation of the Decision.

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C.

Pursuant to the settlement negotiations, the Settling Parties entered into that certain Settlement Agreement, dated October 8, 2010 (the “Settlement Agreement”), which resolved certain issues pending in Rulemakings 99-11-022, 04-04-003, 04-04-025, and 06-02-013, and Application 08-11-001.

D.

The Settlement Agreement became effective on November 23, 2011 (the “Settlement Effective Date”).

E.

Buyer is offering this Agreement to Seller in accordance with the requirements set forth in the Settlement Agreement, and Seller desires to enter into such Agreement.

G.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition EEI Agreement, including the Transition Tolling Confirmation and the Transition RA Confirmation.

H.

Pursuant to the terms and conditions set forth in the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation, Buyer will purchase from Seller and Seller will sell to Buyer the Product (as such term, in this instance only for purposes of this Agreement, is defined in each of the Transition EEI Agreement, the Transition RA Confirmation and the Transition Tolling Confirmation).

The Parties, intending to be legally bound, agree as follows:

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ARTICLE ONE. 1.01

SPECIAL CONDITIONS

Term. The term of this Agreement (the “Term”) commences on [Date] (the “Term Start Date”)the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained (the “Term Start Date”); provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Term shall not commence until all of the condition precedents set forth in each of the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Term Start Date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03)), and ends [Date] (the “Term End Date”). the date that is immediately prior to the commencement of the ‘Term’ under and as defined in the RFO Agreement, which shall be no later than June 30, 2014 (the “Term End Date”); provided, however if ‘CPUC Approval’ (as defined in the RFO Agreement) and/or ‘FERC Approval’ (as defined in the RFO Agreement) of the RFO Agreement are not obtained prior to June 30, 2014, through no fault of Seller, then the Term End Date shall be June 30, 2015. The Term Start Date must occur on the first day following the termination of [insert title and date of the existing power purchase agreement between SCE and Seller, including any amendments, as well as any extension agreementsthe Amended and Restated Parallel Generation Agreement between Sycamore Cogeneration Company and Southern California Edison Company dated September 3, 1986, as amended and supplemented from time to time, and extended by letter agreement entered into pursuant D.07-09-040] dated June 25, 2008 (the “Existing PPA”). {SCE Comment: Seller designates the Term Start Date and the Term End Date; provided, however, that the Term must end on or before July 1, 2015. This Agreement may only be entered into with the California investor-owned utility with which Seller has an existing power purchase agreement (or an extension thereof as ordered by the CPUC in D.07-09-040).}

1.02

Generating Facility. (a)

Name; Designation. The name of the Generating Facility is [Generating Facility name]Units together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation is Sycamore Cogeneration Company, which is an Existing Qualifying Cogeneration Facility.

(b)

Location; Site. The Generating Facility is located at [Generating Facility address],SW China Grade Loop, Bakersfield, CA 93308, and is further described in Exhibit B.

(c)

Qualifying Cogeneration Facility Type. As of the Effective Date, the Generating Facility, which includes the Generating Units together with the

Article One

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generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation, is a [“topping-cycle cogeneration facility”, as defined in 18 CFR Part 292, Section 292.202(d)] [“bottoming-cycle cogeneration facility”, as defined in 18 CFR Part 292, Section 292.202(e)]. (d)

Contract Capacity. As set forth in the following table, Seller may elect (i) only Firm Contract Capacity, (ii) only As-Available Contract Capacity, or (iii) both Firm Contract Capacity and As-Available Contract Capacity: Month January February March April May June July August September October November December

Monthly Firm Contract Capacity (kW) [___] 152,000 [___] 151,000 [___] 151,000 [___] 149,000 [___] 149,000 [___] 148,000 [___] 147,000 [___] 147,000 [___] 147,000 [___] 149,000 [___] 151,000 [___] 152,000

As-Available Contract Capacity (kW/) [___] 0 [___] 1,000 [___] 1,000 [___] 3,000 [___] 3,000 [___] 4,000 [___] 5,000 [___] 5,000 [___] 5,000 [___] 3,000 [___] 1,000 [___]0

Net Contract Capacity (kW) [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000 [___]152,000

{SCE Comment: The Net Contract Capacity must equal the sum of Firm Contract Capacity and As-Available Contract Capacity, and cannot exceed PMax.} Firm

Contract Capacity, As-Available Contract Capacity and Net Contract Capacity are subject to adjustment in accordance with Section 3.07(c). Subject to adjustment in accordance with Section 3.07(c), the Firm Contract Capacity for all months of the year must be less than or equal to [___]152,000 kW, and the As-Available Contract Capacity for all months of the year must be less than or equal to [___] kW.{SCE Comment: Insert the amount of firm capacity and/or as-available capacity, as applicable, historically made available to SCE by Seller under the Parties’ existing power purchase agreement (or an extension thereof as ordered by the CPUC in D.07-09-040).} 5,000 kW, and the sum of Firm Contract

Capacity and As-Available Contract Capacity for all months of the year must be less than or equal to 152,000 kW. (e)

Expected Term Year Energy Production. (i)

Article One

The Expected Term Year Energy Production for each Term Year equals [___]1,280,000,000 kWh.

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{SCE Comment: Expected Term Year Energy Production cannot exceed Net Contract Capacity at 100% capacity factor applied over the Term Year.}

(ii)

The Expected Term Year Energy Production may be revised in accordance with Section 3.07(c), or based on changes in the Site Host Load or the Site Host thermal requirements; provided, however, that such revision must be supported by a certification from a California-licensed professional engineer qualified to make a representation affirming that such revision is reasonable and based on (i) actual modifications to the Generating Facility performed or to be performed by Seller in accordance with and subject to Section 3.07(c), or (ii) changes in the Site Host Load or the Site Host thermal requirements. Such certification must include all data relied on to support the revised Expected Term Year Energy Production.

(iii)

Subject to adjustments in accordance with Section 1.02(e)(ii), the Expected Term Year Energy Production may never exceed [___]1,280,000,000 kWh in any Term Year.

{SCE Comment: Insert the amount of electric energy historically delivered to SCE by Seller under the Parties’ existing power purchase agreement (or an extension thereof as ordered by the CPUC in D.07-09-040)}.

1.03

Delivery Point. The delivery point is the point of delivery of the Power Product to the CAISO Controlled Grid which shall be between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal Magunden 230 kV line (the “Delivery Point”). Seller shall provide and convey to Buyer the Power Product from the Generating Facility at the Delivery Point. Title to and risk of loss related to the Power Product transfer from Seller to Buyer at the Delivery Point.

1.04

Capacity Performance Requirements. As further described in Exhibit D, if the Generating Facility elects to provide Firm Contract Capacity, then the Generating Facility must have a minimum Firm Contract Capacity performance requirement of 95% to earn the Maximum Firm Capacity Payment and a minimum Capacity Performance Requirement of 60% to earn any portion of the Maximum Firm Capacity Payment.

1.05

Maintenance Outages; Major Overhaul.

Article One

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1.06

(a)

The total Maintenance Debit Value for Maintenance Outages, as determined in accordance with Exhibit E, may not exceed 550 hours in the first Term Year. At the end of each Term Year following the first Term Year, up to a maximum of 50 unused hours may be carried over to the following Term Year. For each of the Term Years after the first Term Year, the total Maintenance Debit Value for Maintenance Outages may not exceed 550 hours plus hours carried over from prior Term Years; provided, however, that such Maintenance Debit Value may not exceed 600 hours in any Term Year.

(b)

Seller may (i) request one Major Overhaul Allowance (in accordance with Exhibit E) of up to 750 total hours, (ii) schedule no more than one Major Overhaul; provided, however, that the Maintenance Debit Value for such Major Overhaul may not exceed 750 hours.

(c)

If Seller utilizes all of its Major Overhaul Allowance during a Major Overhaul, the remaining portion of the Major Overhaul may be converted to a Maintenance Outage as far as Maintenance Credit Value and Maintenance Debit Value are concerned; provided, however, that Seller submits a Notice to Buyer of such conversion within 60 days of the end of such Major Overhaul.

(d)

During the Peak Months, Seller may only schedule Maintenance Outages during the non-peak hours of such Peak Months, and the monthly Maintenance Debit Value for Maintenance Outages during the Peak Months may not exceed 12 non-peak hours per Peak Month. Such limitation is part of, and not in addition to, the annual limits as set forth in Section 1.05(a).

Power Product Prices. (a)

Firm Capacity Price. The Firm Capacity Price equals $91.97 per kW-year.

(b)

As-Available Capacity Price. The As-Available Capacity Price is set forth in Section 3 of Exhibit D.

(c)

TOD Period Energy Price. The TOD Period Energy Price is set forth in Section 2 of Exhibit D.

1.07

[Intentionally omitted.]

1.08

Scheduling Coordinator Election. [Buyer][Seller][_________, an agent of Seller] is the Scheduling Coordinator under this Agreement. Notwithstanding anything to the contrary set forth in this Agreement, Buyer must be the Scheduling Coordinator under this Agreement if Seller intends to utilize the exemptions set forth in, and subject to, Sections 3.06(b) or 3.09(b). *** End of Article One ***

Article One

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ARTICLE TWO.

2.01

SELLER’S SATISFACTION OF OBLIGATIONS BEFORE THE TERM START DATE; TERMINATION; CPUC AND FERC APPROVAL

Seller’s Satisfaction of Obligations before the Term Start Date. Seller shall satisfy each of the following obligations before the Term Start Date: (a)

The Generating Facility is a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(b)

Seller enters into all agreements, obtains all Governmental Authority approvals and Permits, and takes all steps necessary for it to: (i)

Operate the Generating Facility;

(ii)

Deliver electric energy from the Generating Facility to the Delivery Point; and

(iii)

Schedule, or arrange for a third party or Buyer to Schedule, the electric energy produced by the Generating Facility with the CAISO;

(c)

Seller’s Scheduling Coordinator, as set forth in Section 1.08, is authorized by the CAISO to Schedule the electric energy produced by the Generating Facility with the CAISO;

(d)

Seller satisfies its obligation to install the CAISO-Approved Meters, as set forth in this Agreement;

(e)

Seller furnishes to Buyer the insurance documents required under Section 9.10(c);

(f)

Seller is in compliance with the CAISO Tariff as set forth in this Agreement;

(g)

Seller enters into and fulfills all of its obligations under (i) the applicable interconnection agreements with the applicable Transmission Provider that are required to enable Parallel Operation of the Generating Facility with the interconnected electric system and the CAISO Controlled Grid, and (ii) any transmission, distribution or other service agreement that are required to enable Seller to transmit electric energy from the Generating Facility to the Delivery Point;

(h)

Seller furnishes to Buyer the documents required under Section 3.05; and

(i)

If Buyer is Scheduling Coordinator and the Generating Facility is PIRP-eligible, then the Generating Facility is certified as a PIRP resource by the CAISO.

Article Two

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2.02

Termination Rights of the Parties. (a)

[Intentionally omitted.]

(b)

Termination Right of Seller.

(c)

Article Two

(i)

Seller has the right to terminate this Agreement if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected by Buyer in a competitive solicitation. In such an instance, the termination of this Agreement will be effective as of midnight the day before the commencement of any delivery period for any electric energy, capacity or attributes from the Generating Facility which is selected by Buyer in such competitive solicitation.

(ii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility are jointly selected in a competitive solicitation by a California investor-owned utility (other than Buyer) that is a party to the Settlement Agreement.

(iii)

Seller has the right to terminate this Agreement upon providing to Buyer at least 180 days advance Notice if Seller (or any venture in which Seller is a participant) and the Generating Facility jointly enter into an agreement for the sale of electric energy, capacity or attributes with a California investorowned utility (other than Buyer) that is a party to the Settlement Agreement.

Event of Default. In the event of an uncured Event of Default or an Event of Default for which there is no opportunity for cure permitted in this Agreement, the Non-Defaulting Party may, at its option, terminate this Agreement as set forth in Section 6.02 and, if the Non-Defaulting Party is Buyer, then Seller (or any entity over which Seller or any owner or manager of Seller exercises control) agrees to waive any right it may have to enter into any new mandatory mustpurchase contract (including the Transition PPA, the QF PPA, or the Optional AsAvailable PPA, as such terms are defined in the Settlement Agreement) to sell electric energy, capacity or Related Products from the Generating Facility to Buyer or any other California investor-owned utility for a period of 365 days following the date of such termination. For purposes of this Section 2.02(c), “control” means the direct or indirect ownership of 20% or more of the outstanding capital stock or other equity interests having ordinary voting power.

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2.03

2.04

(d)

End of Term. This Agreement automatically terminates at 11:59 p.m. PPT on the Term End Date.

(e)

Failure to Obtain CPUC Approval or FERC Approval. If CPUC Approval or FERC Approval has not been obtained by the Term End Date, this Agreement shall terminate in accordance with Section 2.02(d).

(f)

Termination of the Transition EEI Agreement. If the Transition EEI Agreement is terminated before the commencement of the Delivery Period of either the Transition Tolling Confirmation or the Transition RA Confirmation (as defined therein), then this Agreement will automatically terminate, without liability for a Forward Settlement Amount by either Party, on the date of the termination of the Transition EEI Agreement.

Rights and Obligations Surviving Termination. The rights and obligations of the Parties that are intended to survive a termination of this Agreement are all such rights and obligations that this Agreement expressly provides survive such termination as well as those rights and obligations arising from either Parties’ covenants, agreements, representations or warranties applicable to, or to be performed, at, before or as a result of the termination of this Agreement, including: (a)

The obligation of Buyer to make all outstanding Monthly Contract Payments for periods before termination of this Agreement;

(b)

The obligation of Buyer to invoice Seller for all payment adjustments for periods before termination of this Agreement, as set forth in Section 4.02;

(c)

The obligation of Seller to pay any Buyer payment-adjustment invoice described in Section 4.03(b) for periods before termination of this Agreement within 30 days of Seller’s receipt of such invoice;

(d)

The obligation of Buyer or Seller, as applicable, to make payments, if any, after the termination of this Agreement, as set forth in Section 3(c) of Exhibit S;

(e)

The obligation to make a Termination Payment, as set forth in Section 6.03;

(f)

The indemnity obligations, as set forth in Section 9.03;

(g)

The obligation of confidentiality, as set forth in Section 9.09;

(h)

The right to pursue remedies under Section 6.02(c); and

(i)

The limitation of damages under Article Seven.

CPUC Filing and Approval of this Agreement.

Article Two

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2.05

2.06

(a)

Within 60 days after the Effective Date, Buyer shall file with the CPUC the appropriate request for CPUC Approval. Buyer shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use reasonable efforts to support Buyer in obtaining CPUC Approval. Buyer has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Agreement or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Before the Term Start Date, Buyer must have obtained or waived CPUC Approval.

FERC Filing and Approval. (a)

Within 60 days of the Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Agreement or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Agreement will be subject to the dispute resolution provisions in Article Ten. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Effective Date until Buyer provides Seller such independent evaluator report.

(b)

Notwithstanding Seller’s and Buyer’s execution and delivery of this Agreement, this Agreement is subject to FERC Approval and the Term Start Date shall not occur until FERC Approval has been obtained.

Commencement of Term under Confirmations. Notwithstanding anything to the contrary set forth in this Agreement, the Term of this Agreement will not commence until the

Article Two

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commencement of the Delivery Period of the Transition Tolling Confirmation and the Transition RA Confirmation (as defined respectively therein). *** End of Article Two ***

Article Two

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ARTICLE THREE. SELLER’S OBLIGATIONS 3.01

Conveyance of the Product; Retained Benefits. (a)

Product. During the Term, Seller shall provide and convey the Product to Buyer in accordance with the terms of this Agreement, and Buyer shall have the exclusive right to the Product and all benefits derived therefrom, including the exclusive right to sell, convey, transfer, allocate, designate, award, report or otherwise provide any and all of the Product purchased under this Agreement and the right to all revenues generated from the use, sale or marketing of the Product.

(b)

Green Attributes. Seller hereby provides and conveys all Green Attributes associated with the Related Products as part of the Product being delivered during the Term. Seller represents and warrants that Seller holds the rights to all Green Attributes associated with the Related Products, and Seller agrees to convey and hereby conveys all such Green Attributes to Buyer as included in the delivery of the Product from the Project.

(c)

Further Action by Seller. Seller shall, at its own cost, take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term, which actions may include:

Article Three

(i)

Cooperating with the Governmental Authority responsible for resource adequacy administration to certify the Generating Facility for resource adequacy purposes;

(ii)

Testing the Generating Facility as may be required to certify the Generating Facility for resource adequacy purposes in accordance with the requirements set forth in the CAISO Tariff or as otherwise agreed to by the Parties;

(iii)

Committing to Buyer the Net Contract Capacity; and

(iv)

Complying with Applicable Laws regarding the registration, transfer or ownership of Green Attributes associated with the Related Products, including, if applicable to the Generating Facility, participation in WREGIS or other process recognized under Applicable Laws. With respect to WREGIS, at Buyer’s option, Seller shall cause and allow Buyer to be the “Qualified Reporting Entity” and “Account Holder” (as these two terms are defined by WREGIS) for the Generating Facility;

(v)

Complying with all CAISO Tariff requirements applicable to a Resource Adequacy Resource; and

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(vi)

(d)

3.02

If Buyer is not the Scheduling Coordinator: 1)

Timely submitting, or causing Seller’s Scheduling Coordinator to timely submit, Supply Plans to identify and confirm the Net Qualifying Capacity of the Generating Facility sold to Buyer as a Resource Adequacy Resource; and

2)

Causing the Generating Facility’s Scheduling Coordinator to certify to Buyer, within 15 Business Days before the relevant deadline for any applicable RAR Showing or LAR Showing, that Buyer will be credited with the Net Qualifying Capacity of the Generating Facility for such RAR Showing or LAR Showing in the Generating Facility’s Scheduling Coordinator’s Supply Plan.

Retained Benefits. Seller shall retain for its own use or disposition all Financial Incentives and all attributes, benefits and credits associated with the Generating Facility and the electrical or thermal energy produced therefrom, other than the Power Product and the Related Products. Subject to Seller’s compliance with the applicable FERC rules and regulations, Seller may use, provide and convey any electric energy, capacity, Green Attributes, Capacity Attributes, Resource Adequacy Benefits, or any other product or benefit associated with the Generating Facility or the output thereof before the Term Start Date.

Resource Adequacy Rulings. During the Term, Seller shall grant, pledge, assign and otherwise commit to Buyer the generating capacity of the Generating Facility associated with the Related Products in order for Buyer to use in meeting its resource adequacy obligations under any Resource Adequacy Ruling. Seller: (a)

Has not used, granted, pledged, assigned or otherwise committed any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer for any portion of the Term;

(b)

Will not during the Term use, grant, pledge, assign or otherwise commit any portion of the generating capacity of the Generating Facility associated with the Related Products to meet the Resource Adequacy Rulings of, or to confer Resource Adequacy Benefits on, any Person other than Buyer; and

(c)

Shall take all reasonable actions (including complying with all current and future CAISO Tariff provisions and decisions of the CPUC or any other Governmental Authority that address Resource Adequacy Rulings) and execute all documents that are reasonable and necessary to effect the use of the generating capacity of the Generating Facility associated with the Related Products for Buyer’s sole benefit throughout the Term.

Article Three

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3.03

Site Control. Seller shall have Site Control as of the earlier of: (a) the Term Start Date and (b) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term. Seller shall provide Buyer with prompt Notice of any change in the status of Seller’s Site Control.

3.04

Permits. Seller shall obtain and maintain any and all Permits necessary for the Operation of the Generating Facility and to deliver electric energy from the Generating Facility to the Delivery Point.

3.05

Transmission. (a)

Interconnection Studies. Seller has provided Buyer with true and complete copies of all Interconnection Studies received by Seller for the Generating Facility after the date that is 24 months before the Effective Date.

(b)

Seller’s Responsibility. Seller shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable Parallel Operation of the Generating Facility with the Transmission Provider’s electric system and the applicable Control Area operator’s electric grid and to effect Scheduling of the electric energy from the Generating Facility and transmission and delivery to the Delivery Point. Except as otherwise provided in its interconnection agreement, the CAISO Tariff, or the Transmission Provider’s tariff, rules or regulations, Seller shall pay all Transmission Provider charges or other charges directly caused by, associated with, or allocated to the following:

(c)

Article Three

(i)

All required Interconnection Studies, facilities upgrades, and agreements;

(ii)

Interconnection of the Generating Facility to the Transmission Provider’s electric system;

(iii)

Any costs or fees associated with obtaining and maintaining a wholesale distribution access tariff agreement, if applicable; and

(iv)

The transmission and delivery of electric energy from the Generating Facility to the Delivery Point.

Acknowledgement. The Parties acknowledge and agree that any other agreement between Seller and Buyer, including any interconnection agreements, is separate and apart from this Agreement and does not modify or add to the Parties’ obligations under this Agreement, and that any Party’s breach under such other The contents of this document are subject to restrictions on disclosure as set forth herein. Seller’s Obligations

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agreement does not excuse such Party’s nonperformance under this Agreement, except to the extent that such breach constitutes a Force Majeure under this Agreement. 3.06

3.07

CAISO Relationship. (a)

Throughout the Term, Seller shall comply with all applicable provisions of the CAISO Tariff (including complying with any exemption obtained from the CAISO pursuant to the CAISO Tariff), as determined by the CAISO, including securing and maintaining in full force all of the CAISO agreements, certifications and approvals required in order for the Generating Facility to comply with the applicable provisions of the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.06(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not installed one or more CAISO-Approved Meters for the Generating Facility on or before the Term Start Date, Seller will not be in breach of this Agreement with respect to such requirement to install CAISOApproved Meter(s) if Seller installs such CAISO-Approved Meter(s) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement to install CAISO-Approved Meter(s) by complying with a milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to Seller’s requirement that the CAISO-Approved Meters for the Generating Facility be installed on or before the Term Start Date, which extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request.

(c)

Buyer agrees that, subject to the limitation set forth in Section 3.06(b) and upon the CAISO’s request, pending the installation of the CAISO-Approved Meter(s) by Seller for the Generating Facility, Buyer shall provide to the CAISO any settlement quality meter data reasonably requested by the CAISO for settlement purposes.

Generating Facility Modifications. (a)

Article Three

Seller is responsible for the design, procurement and construction of all modifications necessary for the Generating Facility to meet the requirements of this Agreement and to comply with any restriction set forth in any Permit.

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(b)

(c)

Seller shall provide 30 days advance Notice to Buyer if there is any modification (other than a routine fluctuation in output or consumption) of the Generating Facility, the Site Host Load or operations related to the Site Host Load changing: (i)

Electric energy output by five percent of Expected Term Year Energy Production; or

(ii)

The type of Primary Fuel consumed by the Generating Facility.

Seller may not materially modify or repower the Generating Facility without prior written consent of Buyer; provided, however, that modifications or repowering will not be deemed material and is permitted under this Agreement without further consideration, other than Notices required under Section 3.07(b), if: (i)

Capacity added as a result of such modification or repower (including the addition of a steam turbine) over the Term is within the applicable MW limits set forth in the following table (for a Generating Facility with multiple turbines, the limits below are limits per turbine): Current Turbine Name Plate on the Effective Date

Increase to Turbine Name Plate Over the Term

10MW or Less

5MW

Greater than 10MW but less than 20MW

10MW

Greater than or equal to 20MW but less than 25MW

15MW

Greater than or equal to 25MW but less than 50MW

20MW

Greater than or equal to 50MW but less than 100MW

25MW

Greater than or equal to 100 but less than 200MW

35MW

Greater than or equal to 200 but less than 350MW

45MW

Greater than or equal 350MW

50MW

Or, (ii)

Article Three

Such modification or repower is reasonably necessary to respond to a Force Majeure or a change in law or regulation, and a qualified Californialicensed professional engineer verifies that such modification or repower is not oversized relative to other equipment on the market. Seller shall bear the cost of such professional engineer and Seller shall secure all studies and upgrades necessitated by or associated with such modification or repower.

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3.08

(d)

Seller acknowledges that nothing in this Section 3.07 excuses Seller from any requirements of the CAISO’s interconnection process or any other applicable interconnection process.

(e)

Seller is solely responsible for all GHG Compliance Costs and all other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating Facility to the extent that such GHG Compliance Costs or other costs result from Seller’s modification or repowering of the Generating Facility in accordance with this Section 3.07.

Metering. (a)

CAISO-Approved Meter. Seller shall, at its own cost, install, maintain and test all CAISO-Approved Meters pursuant to the CAISO Tariff or other applicable metering requirements.

(b)

Check Meter. Buyer may, at its sole cost, furnish and install one Check Meter at the interconnection associated with the Generating Facility at a location designated by Seller or any other location mutually agreeable to the Parties. The Check Meter location must allow for the Check Meter to be interconnected with Buyer’s communication network to permit: (i)

Periodic, remote collection of revenue quality meter data; and

(ii)

Back-up real time transmission of operating-quality meter data through the Telemetry System set forth in Section 3.09; provided, however, that the transmission of such meter data through the Telemetry System is permitted by the CAISO.

Buyer shall test and recalibrate the Check Meter at least once every Term Year. The Check Meter will be locked or sealed, and the lock or seal shall be broken only by a Buyer representative. Seller has the right to be present whenever such lock or seal is broken. Buyer shall replace the Check Meter battery at least once every 36 months; provided, however, if the Check Meter battery fails, Buyer shall promptly replace such battery. (c)

Article Three

Use of Check Meter for Back-Up Purposes. (i)

Buyer shall routinely compare the Check Meter data to the CAISOApproved Meter data.

(ii)

If the deviation between the CAISO-Approved Meter data (after adjusting (1) for all appropriate compensation and correction factors applied, if applicable, by the CAISO to the CAISO-Approved Meter, or (2) for any

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deviation that may result due to the CAISO-Approved Meter and Check Meter being physically situated in different locations) and the Check Meter data for any comparison is greater than 0.3%, Buyer shall provide Notice to Seller of such deviation and the Parties shall mutually arrange for a meter check or recertification of the Check Meter or CAISOApproved Meter, as applicable.

3.09

(iii)

Each Party shall bear its own costs for any meter check or recertification.

(iv)

Testing procedures and standards for the Check Meter will be the same as for a comparable Buyer-owned meter. Seller shall have the right to have representatives present during all such tests.

(v)

The Check Meter is intended to be used (1) for back-up purposes in the event of a failure or other malfunction of the CAISO-Approved Meter, and (2) in the event Seller has not installed the CAISO-Approved Meter, as further described in Section 3.06(b). Data from the Check Meter will only be used to validate the CAISO-Approved Meter data and, in the event of a failure or other malfunction of the CAISO-Approved Meter, or in accordance with and subject to Section 3.06(b), in place of the CAISOApproved Meter until such time that the CAISO-Approved Meter is certified.

Telemetry System. (a)

Seller is responsible for designing, furnishing, installing, maintaining and testing a real time Telemetry System in accordance with the CAISO Tariff provisions applicable to the Generating Facility. Seller has the right to request any exemption from such requirements from the CAISO so long as it is obtained pursuant to the CAISO Tariff.

(b)

Notwithstanding anything to the contrary set forth in Section 3.09(a), if (i) Buyer is the Scheduling Coordinator under this Agreement, and (ii) Buyer and Seller were, immediately before the Effective Date, parties to the Existing PPA, then, to the extent that Seller would be out of compliance with the CAISO Tariff as of the Term Start Date if Seller has not complied with Section 3.09(a) on or before the Term Start Date, Seller will not be in breach of this Agreement if Seller fully complies with Section 3.09(a) within 180 calendar days after the Effective Date; provided, however, that Seller must demonstrate progress toward compliance with the CAISO Tariff requirement set forth in Section 3.09(a) by complying with a milestone schedule specified by the CAISO in consultation with Seller for satisfaction of this requirement within the 180-calendar-day compliance period. Seller may request further extensions from the CAISO (pursuant to the CAISO Tariff) with respect to the requirement set forth in Section 3.09(a), which

Article Three

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extensions, if approved by the CAISO, must be in writing and provided to Buyer by Seller upon Buyer’s request. (c)

3.10

Buyer agrees that, subject to the limitation set forth in Section 3.09(b) and upon the CAISO’s request, pending Seller compliance with Section 3.09(a), Buyer shall provide to the CAISO any telemetry data reasonably requested by the CAISO for operating information purposes.

Provision of Information. (a)

Article Three

Within 30 days after the Effective Date, Seller shall provide to Buyer (to the extent not already in Buyer’s possession), subject to Section 9.09: (i)

All currently operative agreements with providers of distribution, transmission or interconnection services for the Generating Facility and all amendments thereto;

(ii)

Any currently operative filings at FERC, including any rulings, orders or other pleadings or papers filed by FERC, concerning the qualification of the Generating Facility as a Qualifying Cogeneration Facility;

(iii)

Any Permits reasonably requested by Buyer concerning the Operation or licensing of the Generating Facility, and any applications or filings requesting or pertaining to such Permits;

(iv)

Each of the following engineering documents for the Generating Facility: 1)

Site plan drawings;

2)

Electrical one-line diagrams;

3)

Control and data acquisition details and configuration documents;

4)

Major electrical equipment specifications;

5)

Process flow diagrams;

6)

Piping and instrumentation diagrams;

7)

General arrangement drawings; and

8)

Aerial photographs of the Site, if any; and

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(v)

Instrument specifications, installation instructions, operating manuals, maintenance procedures and wiring diagrams for the CAISO-Approved Meter(s) and the Telemetry System reasonably requested by Buyer.

(b)

If applicable and subject to Section 9.09, as soon as possible, Seller shall provide to Buyer (i) engineering specifications and design drawings for the Telemetry System, and (ii) annual test reports for the CAISO-Approved Meters.

(c)

Subject to Section 9.09 and upon Buyer’s request, Seller shall make commercially reasonable efforts to provide Buyer with all documentation necessary for Buyer to comply with any discovery or data request for information from the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, which commercially reasonable efforts shall, at a minimum, include providing Buyer with all documentation regarding the operational characteristics or past performance of the Generating Facility if such documentation is requested by the CPUC.

3.11

[Intentionally omitted.]

3.12

Fuel Supply. Seller shall supply all fuel required for the Power Product and any testing or demonstration of the Generating Facility.

3.13

Demonstrations. Seller shall comply with any demonstration required for Resource Adequacy Rulings; provided, however, if such demonstrations could interfere with the operations of Seller, Seller shall be entitled to challenge such requirements with the CPUC or other relevant agency. Absent a ruling or other action granting a stay, compliance shall be required pending resolution of the challenge.

3.14

Operation and Record Keeping. Seller shall: (a)

Operate the Generating Facility in accordance with Prudent Electrical Practices;

(b)

Comply with the Forecasting requirements, as set forth in Exhibit I;

(c)

Use reasonable efforts to Operate the Generating Facility so that the Power Product conforms with the Forecast provided in accordance with Exhibit I;

(d)

Pay all CAISO Charges, as set forth in Exhibit J;

(e)

Pay all SDD Adjustments for which Seller is responsible, as set forth in Exhibit K;

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(f)

Comply with the Maintenance Outage scheduling procedures, as set forth in Exhibit E;

(g)

Comply with the Outage Schedule Submittal Requirements, as set forth in Exhibit R;

(h)

Use reasonable efforts to deliver the maximum possible quantity of As-Available Contract Capacity and associated electric energy during an Emergency Condition or a System Emergency;

(i)

Use reasonable efforts to reschedule any outage that occurs during an Emergency Condition or a System Emergency;

(j)

Keep a daily Operating log for the Generating Facility that includes information on availability, outages, circuit breaker trip operations requiring a manual reset, and any significant events related to the Operation of the Generating Facility, including: (i)

Real and reactive power production;

(ii)

Changes in Operating status;

(iii)

Protective apparatus operations; and

(iv)

Any unusual conditions found during inspections;

(k)

Keep all Operating records required of a Qualifying Cogeneration Facility by any applicable CPUC order as well as any additional information that may be required of a Qualifying Cogeneration Facility in order to demonstrate compliance with all applicable California utility industry standards which have been adopted by the CPUC;

(l)

Provide copies of all daily Operating logs and Operating records to Buyer within 20 days of a Notice from Buyer;

(m)

Provide, upon Buyer’s request, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code or any Applicable Law mandating the reporting by investor-owned utilities of expected or experienced outages by facilities under contract to supply electric energy;

(n)

Pay all Scheduling Fees, as set forth in Exhibit G;

(o)

[Intentionally omitted]

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3.15

(p)

Register with the NERC as the Generating Facility’s Generator Owner and Generator Operator if Seller is required to register by the NERC;

(q)

Maintain documentation of all procedures applicable to the testing and maintenance of the Generating Facility protective devices as necessary to comply with the NERC Reliability Standards applicable to protection systems for electric generators if Seller is required to maintain such documentation by the NERC;

(r)

If Buyer is Scheduling Coordinator, then at least 30 days before the Term End Date, or in accordance with Section 7(a) of Exhibit G, or as soon as practicable before the date of an early termination of this Agreement, (i) submit to the CAISO the name of the Scheduling Coordinator that will replace Buyer, and (ii) cause the Scheduling Coordinator that will replace Buyer to submit a letter to the CAISO accepting the designation as Seller’s Scheduling Coordinator; and

(s)

If Buyer is not Scheduling Coordinator: (i)

Cause its Scheduling Coordinator to submit a Self-Schedule of Seller’s Day-Ahead Forecast associated with the Generating Facility through the IFM; Seller shall then submit the quantity associated with the SelfSchedule of Seller’s Day-Ahead Forecast as a Physical Trade to Buyer in the IFM, specifying the generating resource identifier and all other CAISO-required Inter-SC Trade attributes;

(ii)

Cause its Scheduling Coordinator to submit the IFM Day-Ahead Schedule quantity associated with the Generating Facility as an Inter-SC Trade of IFM Load Uplift Obligation to Buyer to be cleared through the Real-Time Market, specifying all CAISO-required Inter-SC Trade attributes; and

(iii)

Make available to Buyer all CAISO settlement data with respect to the Generating Facility required to validate payments made under this Agreement.

Power Product Curtailments at Transmission Provider’s or CAISO’s Request. (a)

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the CAISO, which may be communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when the CAISO orders curtailment and the Scheduling Coordinator implements such curtailment in compliance with the CAISO Tariff or applicable orders to avoid or address a declared System Emergency.

(b)

Seller shall promptly curtail the production of the Power Product upon receipt of a notice or instruction from the Transmission Provider, which may be

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communicated by Buyer if Buyer is the Scheduling Coordinator. Such notice or instruction shall only be provided when curtailment of the Power Product is required to comply with:

(c)

3.16

(i)

A CAISO curtailment declared pursuant to Section 3.15(a) or Transmission Provider declared Emergency Condition, subject to the interconnection agreement between Seller and the Transmission Provider; or

(ii)

Transmission Provider’s maintenance requirements, subject to the interconnection agreement between Seller and the Transmission Provider.

Notwithstanding the above, except as may be required in order to respond to any Emergency Condition or System Emergency, Buyer shall, consistent with FERC Order 888 and the interconnection agreement between Seller and the Transmission Provider and with the applicable provisions of the CAISO Tariff: (i)

Use reasonable good faith efforts to coordinate Transmission Provider’s curtailment needs with Seller to the extent it can influence such needs; or

(ii)

Request the Transmission Provider and CAISO limit the curtailment duration.

(d)

If Seller has entered into a QF PGA or PGA with the CAISO, or an interconnection agreement, the terms of the applicable QF PGA or PGA and the applicable interconnection agreement with respect to CAISO or Transmission Provider curtailments, shall govern the rights and obligations of Buyer and Seller to the extent any provision of this Section 3.15 is inconsistent with such applicable QF PGA or PGA, and interconnection agreement.

(e)

In the event Seller interconnects with a Person other than the CAISO, Seller shall adhere to any reliability curtailment order by such Person pursuant to the applicable tariff provisions of such Person.

Report of Lost Output. To the extent the conditions set forth in Sections 3.16(a) through (e) occur, Seller shall prepare and provide to Buyer, by the fifth Business Day following the end of each month during the Term, a lost output report. The lost output report shall identify the date, time, duration, cause and amount by which the Metered Energy was reduced below the Seller’s Energy Forecast due to: (a)

Maintenance Outages;

(b)

Major Overhauls;

(c)

CAISO or Transmission Provider-ordered curtailments;

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3.17

(d)

Force Majeure; or

(e)

Forced Outages.

FERC Qualifying Cogeneration Facility Status. (a)

Subject to Section 9.09, within 30 Business Days following the end of each year, and within 30 Business Days following the Term End Date, Seller shall provide to Buyer: (i)

A completed copy of Buyer’s “QF Efficiency Monitoring Program – Cogeneration Data Reporting Form”, substantially in the form of Exhibit T, with calculations and verifiable supporting data, which demonstrates the compliance of the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation with qualifying cogeneration facility operating and efficiency standards set forth in 18 CFR Part 292, Section 292.205 “Criteria for Qualifying Cogeneration Facilities”, for the applicable year; andor

(ii)

A copy of a FERC order waiving for the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation the applicable operating and efficiency standards for qualifying cogeneration facilities, as contemplated in 18 CFR Part 292, Section 292.205, “Criteria for Qualifying Cogeneration Facilities”, for the applicable year, if Seller has received such FERC order; provided, that in the event that Seller receives such a FERC order after the time periods set forth above, Seller shall satisfy this requirement by submitting such FERC order to Buyer within 5 Business Days after FERC’s issuance of such FERC order.

(b)

[Intentionally omitted.]

(c)

Seller shall take all necessary steps, including making or supporting timely filings with the FERC in order to maintain, or obtain a FERC waiver of, the Qualifying Cogeneration Facility status of the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation throughout the Term; provided, however, that this obligation does not apply to the extent Seller is unable to maintain Qualifying Cogeneration Facility status using commercially reasonable efforts because of (i) a change in PURPA or in regulations of the FERC implementing PURPA occurring after the Effective Date, or (ii) a change in Applicable Laws directly impacting the Qualifying

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Cogeneration Facility status of the Generating FacilityUnits together with the generating equipment combinations that are subject to the obligations in the Transition Tolling Confirmation and the Transition RA Confirmation occurring after the Effective Date. The term “commercially reasonable efforts” in this Section 3.17(c) does not require Seller to pay or incur more than $20,000 multiplied by the number of Term Years in the Term. 3.18

3.19

Notice of Cessation or Termination of Service Agreements. Seller shall provide Notice to Buyer within one Business Day if there is a termination of, or cessation of service under, any agreement required in order for the Generating Facility to: (a)

Interconnect with the Transmission Provider’s electric system;

(b)

Transmit and deliver electric energy to the Delivery Point; or

(c)

Own and operate any CAISO-Approved Meter.

Buyer’s Access Rights. (a)

(b)

3.20

Upon providing at least one Business Day advance Notice to Seller, or as set forth in any Applicable Law (whichever is later), Buyer has the right to examine the Site, the Generating Facility and the Operating records, provided that Buyer follows Seller’s safety policies and procedures that Seller has communicated to Buyer, does not interfere with or hinder Seller’s Operations, and agrees to escorted access to the Generating Facility during regular business hours for: (i)

Any purpose reasonably connected with this Agreement;

(ii)

The exercise of any and all rights of Buyer under Applicable Law or its tariff schedules and rules on file with the CPUC; or

(iii)

The inspection and testing of any Check Meter, CAISO-Approved Meter or the Telemetry System.

Seller shall promptly provide Buyer access to all meter data and data acquisition services both in real-time, and at later times, as Buyer may reasonably request. Seller shall promptly inform Buyer of meter quantity changes after becoming aware of, or being informed of, any such changes by the CAISO. Seller shall provide instructions to the CAISO granting authorizations or other documentation sufficient to provide Buyer with access to the CAISO-Approved Meter and to Seller’s settlement data on OMAR.

Seller Financial Information.

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(a)

The Parties shall determine, through consultation and review with their respective independent registered public accounting firms, whether Buyer is required to consolidate Seller’s financial statements with Buyer’s financial statements for financial accounting purposes under Accounting Standards Codification (ASC) 810/Accounting Standards Update 2009-17, “Consolidation of Variable Interest Entities” (ASC 810), or future guidance issued by accounting profession governance bodies or the SEC that affects Buyer accounting treatment for this Agreement (the “Financial Consolidation Requirement”).

(b)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then: (i)

Within 20 days following the end of each year (for each year that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the year. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements. The annual financial statements should include quarter-to-date and yearly information. Buyer shall provide to Seller a checklist before the end of each year listing the items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with true-up to actual activity, in subsequent periods, when preparing the information on the checklist. If audited financial statements are prepared for Seller for the year, Seller shall provide such statements to Buyer within five Business Days after those statements are issued.

(ii)

Within 15 days following the end of each fiscal quarter (for each quarter that such treatment is required), Seller shall deliver to Buyer unaudited financial statements and related footnotes of Seller as of the end of the quarterly period. The financial statements should include quarter-to-date and year-to-date information. Buyer shall provide to Seller a checklist before the end of each quarter listing items which Buyer believes are material to Buyer and required for this purpose, and Seller shall provide the information on the checklist, subject to the availability of data from Seller’s records. It is permissible for Seller to use accruals and prior month’s estimates with

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true-up to actual activity, in subsequent periods, when preparing the unaudited financial statements. (iii)

(c)

If Seller regularly prepares its financial data in accordance GAAP, the International Financial Reporting Standards (“IFRS”), or any successor to either of the foregoing (“Successor”), the financial information provided to Buyer shall be prepared in accordance with such principles. If Seller is not a SEC registrant and does not regularly prepare its financial data in accordance with GAAP, IFRS or Successor, the information provided to Buyer shall be prepared in a format consistent with Seller’s regularly applied accounting principles, e.g., the format that Seller uses to provide financial data to its auditor.

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then promptly upon Notice from Buyer, Seller shall allow Buyer’s independent registered public accounting firm such access to Seller’s records and personnel, as reasonably required so that Buyer’s independent registered public accounting firm can conduct financial statement audits in accordance with the standards of the Public Company Accounting Oversight Board (United States), as well as internal control audits in accordance with Section 404 of the Sarbanes-Oxley Act of 2002, as applicable. All expenses for the foregoing shall be borne by Buyer. If Buyer’s independent registered public accounting firm during or as a result of the audits permitted in this Section 3.20(c) determines a material weakness or significant deficiency, as defined by GAAP, IFRS or Successor, as applicable, exists in Seller’s internal controls over financial reporting, then within 90 days of Seller’s receipt of Notice from Buyer, Seller shall remediate any such material weakness or significant deficiency; provided, however, that Seller has the right to challenge the appropriateness of any determination of material weakness or significant deficiency. Seller’s true up to actual activity for yearly or quarterly information as provided herein shall not be evidence of material weakness or significant deficiency.

(d)

Buyer shall treat Seller’s financial statements and other financial information provided under the terms of this Section 3.20 in strict confidence and, accordingly: (i)

Article Three

Shall utilize such Seller financial information only for purposes of preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, for making regulatory, tax or other filings required by law in which Buyer is required to demonstrate or certify its or any parent company’s financial condition or to obtain credit ratings;

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3.21

(ii)

Shall make such Seller financial information available only to its officers, directors, employees or auditors who are responsible for preparing, reviewing or certifying Buyer’s or any Buyer parent company financial statements, to the SEC and the Public Company Accounting Oversight Board (United States) in connection with any oversight of Buyer’s or any Buyer parent company financial statement and to those Persons who are entitled to receive confidential information as identified in Sections 9.09(a)(vi) and 9.09(a)(vii); and

(iii)

Buyer shall ensure that its internal auditors and independent registered public accounting firm (1) treat as confidential any information disclosed to them by Buyer pursuant to this Section 3.20, (2) use such information solely for purposes of conducting the audits described in this Section 3.20, and (3) disclose any information received only to personnel responsible for conducting the audits.

(e)

If the Parties mutually agree that the Financial Consolidation Requirement is applicable, then, within two Business Days following the occurrence of any event affecting Seller which Seller understands, during the Term, would require Buyer to disclose such event in a Form 8-K filing with the SEC, Seller shall provide to Buyer a Notice describing such event in sufficient detail to permit Buyer to make a Form 8-K filing.

(f)

If, after consultation and review, the Parties do not agree on issues raised by Section 3.20(a), then such dispute shall be subject to review by another independent audit firm not associated with either Party’s respective independent registered public accounting firm, reasonably acceptable to both Parties. This third independent audit firm will render its recommendation on whether consolidation by Buyer is required. Based on this recommendation, Seller and Buyer shall mutually agree on how to resolve the dispute. If Seller fails to provide the data consistent with the mutually agreed upon resolution, Buyer may declare an Event of Default pursuant to Section 6.01. If Buyer’s independent audit firm, after the review by the third independent audit firm still determines that Buyer must consolidate, then Seller shall provide the financial information necessary to permit consolidation to Buyer; provided, however, that in addition to the protections in Section 3.20(d), such information shall be password protected and available only to those specific officers, directors, employees and auditors who are preparing and certifying the consolidated financial statements and not for any other purpose.

NERC Electric System Reliability Standards. During the Term, for purposes of complying with any NERC Reliability Standards applicable to the Generating Facility, Seller (or an agent of Seller as agreed to by Buyer in its reasonable discretion) must, if required by the NERC, register with the NERC as the Generator Operator and the

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Generator Owner for the Generating Facility and must perform all Generator Operator Obligations and Generator Owner Obligations except those Generator Operator Obligations that Buyer, in its capacity as Scheduling Coordinator (if Seller has elected to have Buyer serve as its Scheduling Coordinator), is required to perform under this Agreement or under the CAISO Tariff. Notwithstanding anything to the contrary set forth in this Section 3.21 and subject to the indemnity obligations set forth in Section 9.03(h), each Party acknowledges that such Party’s performance of the Generator Operator Obligations or Generator Owner Obligations may not satisfy the requirements for self-certification or compliance with the NERC Reliability Standards, and that it shall be the sole responsibility of each Party to implement the processes and procedures required by the NERC, the WECC, the CAISO, or a Governmental Authority in order to comply with the NERC Reliability Standards. If Buyer is Seller’s Scheduling Coordinator, Buyer as Scheduling Coordinator will reasonably cooperate with Seller to the extent necessary to enable Seller to comply and for Seller to demonstrate Seller’s compliance with the NERC Reliability Standards referenced above. Buyer’s cooperation will include providing to Seller, or such other Person as Seller designates in writing, information in Buyer’s possession that Buyer as Scheduling Coordinator has provided to the CAISO related to the Generating Facility or actions that Buyer has taken as Scheduling Coordinator related to Seller’s compliance with the NERC Reliability Standards referenced above (e.g., Seller’s notices and updates provided by Buyer to the CAISO via SLIC). Buyer may, in its reasonable discretion (depending upon the quantity of information requested by Seller and the timeframe established by Seller for compliance), comply with the requirement to provide information set forth in the previous sentence, by making such information available for inspection by Seller or by providing responsive summaries or excerpts of same, so long as the foregoing enables Seller to comply with the NERC Reliability Standards. In addition, Buyer may redact any information or data that is confidential to Buyer from materials or information to be supplied to Seller. 3.22

Allocation of Availability Incentive Payments and Non-Availability Charges. (a)

If Buyer is the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of Buyer and for Buyer’s account and any Non-Availability Charges will be the responsibility of Buyer and for Buyer’s account.

(b)

If Buyer is not the Scheduling Coordinator, and if the Generating Facility is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the CAISO Tariff, then any Availability Incentive Payments will be for the benefit of

Article Three

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Seller and for Seller’s account and any Non-Availability Charges will be the responsibility of Seller and for Seller’s account. 3.23

Seller’s Reporting Requirements. (a)

Seller shall comply with the reporting requirements set forth in Section 3 of Exhibit S.

(b)

Seller shall deliver to Buyer, on or before the 10th Business Day following receipt of a Notice from Buyer, such information that Buyer is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Buyer otherwise requires in order to comply with the Settlement Agreement. *** End of Article Three ***

Article Three

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

ARTICLE FOUR.

BUYER’S OBLIGATIONS

4.01

Obligation to Pay. For Seller’s full compensation under this Agreement, during the Term, Buyer shall make a monthly payment (a “Monthly Contract Payment”) calculated in accordance with Exhibit D.

4.02

Payment Adjustments. (a)

Buyer shall adjust each Monthly Contract Payment to Seller to account for: (i)

Scheduling Fees owed by Seller to Buyer, as set forth in Exhibit G;

(ii)

Any SDD Adjustment, as set forth in Exhibit K;

(iii)

Any Forecast penalties owed by Seller to Buyer, as set forth in Exhibit I;

(iv)

Any CAISO Charges owed by Seller to Buyer, as set forth in Exhibit J;

(v)

Any Physical Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit L;

(vi)

Any SC Trade Settlement Amount owed by either Party to the other Party, as set forth in Exhibit M;

(vii)

Any payment adjustments (including adjustments to CAISO Charges) provided for under this Agreement;

(viii) Any Governmental Charges owed by either Party to the other Party, as set forth in Section 8.02;

(b)

Article Four

(ix)

The agreement of the Parties that Buyer shall have no liability to make any energy payments to Seller for any electricity deliveries from the Generating Facility in a Term Year that exceed 120% of Expected Term Year Energy Production; and

(x)

Any payment adjustments provided for to determine Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges, as set forth in Exhibit S.

Unless otherwise required in Exhibit S, during the Term, any payment adjustments will be added to or deducted from a subsequent regular Monthly Contract Payment that is made by Buyer to Seller after the expiration of a 30-day period which begins upon Buyer’s receipt of all of the information required in order to calculate payment adjustments.

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(c)

4.03

Unless otherwise required in Exhibit S, after the Term End Date, Buyer shall invoice Seller for all payment adjustments within 60 days of Buyer’s receipt of all of the information required in order to calculate payment adjustments.

Payment Statement and Payment. (a)

No later than 30 days after the end of each calendar month (or the last day of the month if the month in which the payment statement is being sent is February), or the last Business Day of the month if such 30th day (or 28th or 29th day for February) is not a Business Day, Buyer shall mail to Seller: (i)

(ii)

(iii)

Article Four

A table showing the hourly electric energy quantities for each of the following, in MWh per hour: 1)

Seller’s Energy Forecast;

2)

Seller’s Day-Ahead Forecast;

3)

Metered Energy;

4)

Metered Amounts;

5)

The final Buyer Energy Schedule; and

6)

The final Buyer Parent Energy Schedule.

A statement showing: 1)

TOD Period subtotals and overall monthly totals for each of the items set forth in Section 4.03(a)(i);

2)

A calculation of the Monthly Contract Payment, as set forth in Exhibit D;

3)

A calculation of any payment adjustments pursuant to Section 4.02;

4)

A calculation of any payment adjustments pursuant to Exhibit S; and

5)

A calculation of the net dollar amount due for the month.

Buyer’s payment to Seller, in accordance with Section 9.15, in the net dollar amount owed to Seller for the month (less any overpayments by Buyer of Seller’s GHG Compliance Costs or GHG Charges under Section

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

4.04 in any calendar month); provided, however, in the event the statement shows a net amount owed to Buyer, Seller shall pay such amount within 20 days of the statement date or, if Seller fails to make such payment, Buyer may offset this amount from a subsequent Monthly Contract Payment. (b)

If Buyer determines that a calculation of Metered Energy or Metered Amounts is incorrect as a result of an inaccurate meter reading or the correction of data by the CAISO in the CAISO’s meter-data acquisition and processing system, Buyer shall promptly recompute the Metered Energy or Metered Amounts quantity for the period of the inaccuracy based on an adjustment of such inaccurate meter reading in accordance with the CAISO Tariff. Buyer shall then promptly recompute any payment or payment adjustment affected by such inaccuracy. Any amount due from Buyer to Seller or Seller to Buyer, as the case may be, shall be made as an adjustment to the next monthly statement that is calculated after Buyer’s recomputation using corrected measurements. If the recomputation results in a net amount owed to Buyer after offsetting any amounts owing to Seller as shown on the next monthly statement, any such additional amount still owing to Buyer shall be shown as an adjustment on Seller’s monthly statement until such amount is fully collected by Buyer. At Buyer’s sole discretion, Buyer may offset any remaining amount owed to Buyer in any subsequent monthly payments to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice.

(c)

(d)

Article Four

Buyer reserves the right to deduct amounts that would otherwise be due to Seller under this Agreement from any amounts owing and unpaid by Seller to Buyer: (i)

Under this Agreement; or

(ii)

Arising out of or related to any other agreement, tariff, obligation or liability pertaining to the Generating Facility.

Except as provided in Section 4.03(b) and as otherwise provided in this Section 4.03(d), if, within 45 days of receipt of Buyer’s payment statement, Seller does not give Notice to Buyer of an error, then Seller shall be deemed to have waived any error in Buyer’s statement, computation and payment and the statement shall be conclusively deemed correct and complete; provided, however, that if an error is identified by Seller as a result of settlement, audit or other information provided to Seller by the CAISO after the expiration of the original 45-day period, Seller The contents of this document are subject to restrictions on disclosure as set forth herein. Buyer’s Obligations

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

shall have an additional 90 days from the date on which it receives the information from the CAISO in which to give Notice to Buyer of the error identified by such settlement, audit or other information. If Seller identifies an error in Seller’s favor and Buyer agrees that the identified error occurred, Buyer shall reimburse Seller for the amount of the underpayment caused by the error and add the underpayment to the next monthly statement that is calculated. If Seller identifies an error in Buyer’s favor and Buyer agrees that the identified error occurred, Seller shall reimburse Buyer for the amount of overpayment caused by the error and Buyer shall apply the overpayment to the next monthly statement that is calculated. If the recomputation results in a net amount still owing to Buyer after applying the overpayment, the next monthly statement shall show a net amount owing to Buyer. At Buyer’s sole discretion, Buyer may apply this net amount owing to Buyer in any subsequent monthly statements to Seller or invoice Seller for such amount, in which case Seller must pay the amount owing to Buyer within 20 days of receipt of such invoice. The Parties shall negotiate to resolve any disputes regarding claimed errors in a statement. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. Nothing in this Section 4.03 limits a Party’s rights under applicable tariffs, other agreements or Applicable Law. 4.04

GHG Compliance Costs. Buyer shall pay for Seller’s GHG Compliance Costs and GHG Charges in accordance with Exhibit S; provided, however, that notwithstanding anything to the contrary set forth in this Agreement (including Exhibit S), in no event will Buyer pay for any of Seller’s GHG Compliance Costs or GHG Charges to the extent that such GHG Compliance Costs or GHG Charges are associated with deliveries of the Power Product that are in excess of 120% of the Expected Term Year Net Energy Production in any Term Year.

4.05

No Representation by Buyer. Any review by Buyer of the design, engineering, construction, testing and Operation of the Generating Facility is solely for Buyer’s information. Buyer makes no representation that:

Article Four

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(a)

It has reviewed the financial viability, technical feasibility, operational capability, or long term reliability of the Generating Facility;

(b)

The Generating Facility complies with any Applicable Laws; or

(c)

The Generating Facility will be able to meet the terms of this Agreement.

Seller shall in no way represent to any third party that any such review by Buyer constitutes any such representation. 4.06

Buyer’s Responsibility. Buyer shall obtain and maintain all distribution, transmission and interconnection rights and agreements (including all Governmental Authority approvals) required to enable transmission and delivery of electric energy at and after the Delivery Point.

4.07

Buyer’s Reporting Requirements. Buyer shall deliver to Seller, on or before the 10th Business Day following receipt of a Notice from Seller, such information as Seller is required to report to any authorized Governmental Authority pursuant to the Settlement Agreement, or which Seller otherwise requires in order to comply with the Settlement Agreement. *** End of Article Four ***

Article Four

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

ARTICLE FIVE.

FORCE MAJEURE

5.01

No Default for Force Majeure. Neither Party will be in default in the performance of any of its obligations set forth in this Agreement, except for obligations to pay money, when and to the extent failure of performance is caused by Force Majeure.

5.02

Requirements Applicable to the Claiming Party. If a Party, because of Force Majeure, is rendered wholly or partly unable to perform its obligations when due under this Agreement, such Party (the “Claiming Party”) shall be excused from whatever performance is affected by the Force Majeure to the extent so affected. In order to be excused from its performance obligations under this Agreement by reason of Force Majeure: (a)

The Claiming Party, within 14 days after the initial occurrence of the claimed Force Majeure, must give the other Party Notice describing the particulars of the occurrence; and

(b)

The Claiming Party must provide timely evidence reasonably sufficient to establish that the occurrence constitutes Force Majeure as defined in this Agreement.

The suspension of the Claiming Party’s performance due to Force Majeure may not be greater in scope or longer in duration than is required by such Force Majeure. In addition, the Claiming Party shall use diligent efforts to remedy its inability to perform. This Article Five will not require the settlement of any strike, walkout, lockout or other labor dispute on terms which, in the sole judgment of the Claiming Party, are contrary to its interest. It is understood and agreed that the settlement of strikes, walkouts, lockouts or other labor disputes shall be at the sole discretion of the Claiming Party. When the Claiming Party is able to resume performance of its obligations under this Agreement, the Claiming Party shall give the other Party prompt Notice to that effect. 5.03

Termination. Either Party may terminate this Agreement on Notice, which Notice will be effective five Business Days after such Notice is provided, in the event of Force Majeure which materially interferes with such Party’s ability to perform its obligations under this Agreement and which extends for more than 365 consecutive days, or for more than a total of 365 days in any consecutive 540-day period. *** End of Article Five ***

Article Five

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ARTICLE SIX. 6.01

EVENTS OF DEFAULT; REMEDIES

Events of Default. An “Event of Default” means the occurrence of any of the following :

(a)

With respect to either Party (a “Defaulting Party”): (i) Any representation or warranty made by such Party in this Agreement is false or misleading in any material respect when made or when deemed made or repeated if the representation or warranty is continuing in nature, if such misrepresentation or breach of warranty is not:

1) Remedied within 10 Business Days after Notice from the Non-Defaulting Party to the Defaulting Party; or 2) Capable of a cure, but the Non-Defaulting Party’s damages resulting from such misrepresentation or breach of warranty can reasonably be ascertained and the payment of such damages is not made within 10 Business Days after a Notice of such damages is provided by the Non-Defaulting Party to the Defaulting Party; (ii) Except for an obligation to make payment when due, the failure to perform any material covenant or obligation set forth in this Agreement (except to the extent constituting a separate Event of Default or to the extent excused by a Force Majeure) if such failure is not remedied within 30 days after Notice of such failure is provided by the Non-Defaulting Party to the Defaulting Party, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 30-day cure period, the Defaulting Party shall have such additional time (not to exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as such Defaulting Party promptly commences and diligently pursues such cure; (iii) A Party fails to make when due any payment (other than amounts disputed in accordance with the terms of this Agreement) due and owing under this Agreement and such failure is not cured within five Business Days after Notice is provided by the Non-Defaulting Party to the Defaulting Party of such failure; (iv)

A Party becomes Bankrupt; or

(v) A Party consolidates or amalgamates with, or merges with or into, or transfers all or substantially all of its assets to, another Person and, at the time of such consolidation, amalgamation, merger or transfer, the resulting, surviving or transferee Person fails to assume all the obligations of such

Article Six

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Party under this Agreement to which such Party or its predecessor was a party by operation of law or pursuant to an agreement reasonably satisfactory to the other Party.; (vi) An event of default occurs (howsoever determined) under any agreement between Buyer and Seller (other than this Agreement but including the Transition EEI Agreement, the Transition Tolling Confirmation and the Transition RA Confirmation) and, after giving effect to any applicable notice requirement or cure period, there occurs a liquidation of, an acceleration of obligations under, or an early termination of that agreement; or (vii) The Party disaffirms, disclaims, repudiates, or rejects, in whole or in part, or challenges the validity of, the Transition EEI Agreement or the Transition Tolling Confirmation or Transition RA Confirmation. (b)

[Intentionally omitted.]

(c)

With respect to Seller: (i) Seller does not own or lease the Generating Facility or otherwise have the authority over the Generating Facility as required in Section 3.03, and Seller has not cured a failure with respect to Section 3.03 within 30 days after providing Notice to Buyer in accordance with Section 3.03; (ii) If Seller abandons the Generating Facility (for purposes of this Section 6.01(c)(ii), Seller will be deemed to have abandoned the Generating Facility if Seller has ceased work on the Generating Facility or the Generating Facility has ceased production and delivery of the Product for a consecutive thirty (30) day period and such cessation is not a result of an event of Force Majeure); (iii) ExceptDuring the Term, except as provided for in Section 3.01(d), Seller (1) conveys, transfers, allocates, designates, awards, reports or otherwise provides any and all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except as may relate to transactions in the imbalance market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) starts up or Operates the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws);

Article Six

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(iv) Seller intentionally or knowingly delivers, Schedules, or attempts to deliver or Schedule at the Delivery Point for sale under this Agreement electric energy that was not generated by the Generating Facility; (v) Seller removes from the Site equipment upon which the Net Contract Capacity has been based, except for the purposes of replacement, refurbishment, repair, repowering or maintenance, and such equipment is not returned within five Business Days after Notice from Buyer to Seller; (vi) Subject to Section 3.17(c), the Generating Facility fails to maintain its status as a Qualifying Cogeneration Facility; (vii) Termination of, or cessation of service under, any agreement necessary for the interconnection of the Generating Facility to the Transmission Provider’s electric system for transmission and delivery of the electric energy from the Generating Facility to the Delivery Point, or for metering the Metered Energy, and such service is not reinstated, or alternative arrangements implemented, within 120 days after such termination or cessation; (viii) Seller fails to make all reasonable efforts to increase the Power Output from the Generating Facility to the Firm Contract Capacity during an Emergency Condition or a System Emergency; (ix) Seller fails to provide any financial statements or other information within the timeframe and in the manner set forth in Sections 3.20(b)(i) and (ii), and such failure is not remedied within 10 days after Notice from Buyer to Seller; (x) Seller fails to remediate any material weakness or significant deficiency in internal controls over financial reporting in accordance with Section 3.20(c), and such failure is not remedied within 90 days after Notice from Buyer to Seller; (xi) Seller fails to take all reasonable actions and execute all documents or instruments that are reasonable and necessary to effectuate the use of the Related Products for Buyer’s benefit throughout the Term as specified in Section 3.01, if such failure is not remedied within 10 days after Notice of such failure is provided by Buyer to Seller, which Notice sets forth in reasonable detail the nature of the Event of Default; provided, however, that if the Event of Default is not reasonably capable of being cured within such 10-day cure period, Seller shall have such additional time (not to exceed 120 days) as is reasonably necessary to cure such Event of Default, so long as Seller promptly commences and diligently pursues such cure;

Article Six

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(xii)

[Intentionally omitted]

(xiii) If any failure by Seller to comply with the CAISO Tariff materially impacts Buyer’s ability to comply with this Agreement, the CAISO Tariff or other Applicable Laws, and such failure by Seller (including any consequences suffered by Buyer) is not cured within 30 days after Notice from Buyer to Seller; (xiv) If Seller materially modifies or repowers the Generating Facility (except as provided in Section 3.07(c)) without Buyer’s prior written consent; or (xv) If Seller fails to satisfy all of the conditions set forth in Section 2.01 before the Term Start Date, and such failure is not cured within 30 Business Days after Notice from Buyer to Seller. 6.02 Early Termination. If an Event of Default has occurred, there will be no opportunity for cure except as specified in Section 6.01 or pursuant to a Collateral Assignment Agreement agreed upon by Buyer, Seller and Lender in accordance with Section 9.05. The Party taking the default (the “Non-Defaulting Party”) will have the right to: (a) Designate by Notice to the Defaulting Party a date, no later than 20 days after the Notice is effective, for the early termination of this Agreement (an “Early Termination Date”); (b)

Immediately suspend performance under this Agreement; and

(c) Pursue all remedies available at law or in equity against the Defaulting Party (including monetary damages), except to the extent that such remedies are limited by the terms of this Agreement. 6.03 Termination Payment. As soon as practicable after an Early Termination Date is declared, the Non-Defaulting Party shall provide Notice to the Defaulting Party of the sum of all amounts owed by the Defaulting Party under this Agreement less any amounts owed by the NonDefaulting Party to the Defaulting Party under this Agreement, including any Forward Settlement Amount (the “Termination Payment”). The Notice shall include a written statement setting forth, in reasonable detail, the calculation of such Termination Payment, including the Forward Settlement Amount, together with appropriate supporting documentation. If the Termination Payment is positive, the Defaulting Party shall pay such amount to the Non-Defaulting Party within 10 Business Days after the Notice is provided. If the Termination Payment is negative (i.e., the Non-Defaulting Party owes the Defaulting Party more than the Defaulting Party owes the Non-Defaulting Party), then the NonDefaulting Party shall pay such amount to the Defaulting Party within 10 Business Days after the Notice is provided.

Article Six

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The Parties shall negotiate to resolve any disputes regarding the calculation of the Termination Payment and Forward Settlement Amount. Any disputes which the Parties are unable to resolve through negotiation may be submitted for resolution through the dispute resolution procedure in Article Ten. *** End of Article Six ***

Article Six

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ARTICLE SEVEN. LIMITATIONS OF LIABILITIES EXCEPT AS SET FORTH IN THIS ARTICLE SEVEN, THERE ARE NO WARRANTIES BY EITHER PARTY UNDER THIS AGREEMENT, INCLUDING ANY WARRANTY OF MERCHANTABILITY OR FITNESS FOR A PARTICULAR PURPOSE, AND ANY AND ALL IMPLIED WARRANTIES ARE DISCLAIMED. THE PARTIES CONFIRM THAT THE EXPRESS REMEDIES AND MEASURES OF DAMAGES PROVIDED IN THIS AGREEMENT SATISFY THE ESSENTIAL PURPOSES HEREOF. FOR BREACH OF ANY PROVISION FOR WHICH AN EXPRESS REMEDY OR MEASURE OF DAMAGES IS PROVIDED, SUCH EXPRESS REMEDY OR MEASURE OF DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY, THE OBLIGOR’S LIABILITY IS LIMITED AS SET FORTH IN SUCH PROVISION AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED, UNLESS THE PROVISION IN QUESTION PROVIDES THAT THE EXPRESS REMEDIES ARE IN ADDITION TO OTHER REMEDIES THAT MAY BE AVAILABLE. IF NO REMEDY OR MEASURE OF DAMAGES IS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, THE OBLIGOR’S LIABILITY IS LIMITED TO DIRECT ACTUAL DAMAGES ONLY, SUCH DIRECT ACTUAL DAMAGES IS THE SOLE AND EXCLUSIVE REMEDY AND ALL OTHER REMEDIES OR DAMAGES AT LAW OR IN EQUITY ARE WAIVED. THE VALUE OF ANY PRODUCTION TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. THE VALUE OF ANY INVESTMENT TAX CREDITS DETERMINED ON AN AFTER-TAX BASIS, LOST DUE TO BUYER’S DEFAULT (WHICH SELLER HAS NOT BEEN ABLE TO MITIGATE AFTER USE OF REASONABLE EFFORTS) IF ANY, SHALL BE DEEMED DIRECT DAMAGES. UNLESS EXPRESSLY PROVIDED FOR IN THIS AGREEMENT, INCLUDING THE PROVISIONS OF SECTION 9.03, NEITHER PARTY SHALL BE LIABLE FOR CONSEQUENTIAL, INCIDENTAL, PUNITIVE, EXEMPLARY OR INDIRECT DAMAGES, LOST PROFITS OR OTHER BUSINESS INTERRUPTION DAMAGES, BY STATUTE, IN TORT OR CONTRACT, UNDER ANY INDEMNITY PROVISION OR OTHERWISE. IT IS THE INTENT OF THE PARTIES THAT THE LIMITATIONS IMPOSED IN THIS ARTICLE SEVEN ON REMEDIES AND THE MEASURE OF DAMAGES BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY, WHETHER SUCH NEGLIGENCE BE SOLE, JOINT OR CONCURRENT, OR ACTIVE OR PASSIVE.

Article Seven

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

TO THE EXTENT ANY DAMAGES REQUIRED TO BE PAID UNDER THIS AGREEMENT ARE LIQUIDATED, THE PARTIES ACKNOWLEDGE THAT THE DAMAGES ARE DIFFICULT OR IMPOSSIBLE TO DETERMINE, OR OTHERWISE OBTAINING AN ADEQUATE REMEDY IS INCONVENIENT AND THE DAMAGES CALCULATED UNDER THIS AGREEMENT CONSTITUTE A REASONABLE APPROXIMATION OF THE HARM OR LOSS. NOTHING IN THIS ARTICLE SEVEN PREVENTS, OR IS INTENDED TO PREVENT BUYER FROM PROCEEDING AGAINST OR EXERCISING ITS RIGHTS WITH RESPECT TO ANY SECURED INTEREST IN COLLATERAL. *** End of Article Seven ***

Article Seven

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ARTICLE EIGHT. GOVERNMENTAL CHARGES 8.01

Cooperation to Minimize Tax Liabilities. Each Party shall use diligent efforts to implement the provisions of and to administer this Agreement in accordance with the intent of the Parties to minimize all taxes, so long as neither Party is materially adversely affected by such efforts.

8.02

Governmental Charges. Seller shall pay or cause to be paid all taxes imposed by any Governmental Authority (“Governmental Charges”) on or with respect to the Generating Facility, Monthly Contract Payments made by Buyer to Seller, or the Power Product before the Delivery Point, including ad valorem taxes and other taxes attributable to the Generating Facility, the Site or land rights or interests in the Site or the Generating Facility. Buyer shall pay or cause to be paid all Governmental Charges on or with respect to the Power Product at and after the Delivery Point. If Seller is required by Applicable Laws to remit or pay Governmental Charges which are Buyer’s responsibility under this Agreement, Buyer shall promptly reimburse Seller for such Governmental Charges. If Buyer is required by Applicable Law or regulation to remit or pay Governmental Charges which are Seller’s responsibility under this Agreement, Buyer may deduct such amounts from payments to Seller made pursuant to Article Four. If Buyer elects not to deduct such amounts from Seller’s payments, Seller shall promptly reimburse Buyer for such amounts upon Notice from Buyer of the amount to be reimbursed. Nothing shall obligate or cause a Party to pay or be liable to pay any Governmental Charges for which it is exempt under Applicable Laws. Nothing stated in this Section 8.02 relieves Buyer of its obligation to pay Seller for Seller’s GHG Compliance Costs and GHG Charges in accordance with and subject to this Agreement (including Exhibit S).

8.03

Providing Information to Taxing Governmental Authorities. To the extent required by Applicable Law and subject to Section 9.09(b), each Party shall provide information concerning the Generating Facility to any requesting taxing Governmental Authority. *** End of Article Eight ***

Article Eight

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ARTICLE NINE.

MISCELLANEOUS

9.01

Representations, Warranties and Covenants.

(a)

On the Effective Date, each Party represents and warrants to the other Party that:

(i)

It is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;

(ii)

The execution, delivery and performance of this Agreement are within its powers, have been duly authorized by all necessary action and do not violate any of the terms and conditions in its governing documents, any contracts to which it is a party or any Applicable Laws;

(iii)

This Agreement constitutes a legally valid and binding obligation enforceable against it in accordance with its terms, subject to any Equitable Defenses;

(iv)

There is not pending, or to its knowledge, threatened against it or, in the case of Seller, any of its Related Entities, any legal proceeding that could materially adversely affect its ability to perform under this Agreement;

(v)

No Event of Default with respect to it has occurred and is continuing and no such event or circumstance will occur as a result of its entering into or performing its obligations under this Agreement;

(vi)

It is acting for its own account, and its decision to enter into this Agreement is based upon its own judgment, not in reliance upon the advice or recommendations of the other Party and it is capable of assessing the merits of and understanding, and understands and accepts the terms, conditions and risks of this Agreement;

(vii)

It has not relied on any promises, representations, statements or information of any kind whatsoever that are not contained in this Agreement in deciding to enter into this Agreement; and

(viii) It has entered into this Agreement in connection with the conduct of its business and it has the capacity or ability to provide or receive the Power Product as contemplated by this Agreement. (b)

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On the Effective Date, each Party covenants to the other Party that, except for CPUC Approval in the case of Buyer, and for certain authorizations that Seller will need to obtain from FERC, it has or will timely acquire all regulatory authorizations necessary for it to legally perform its obligations under this Agreement.

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(c)

On the Effective Date, Seller represents and warrants to Buyer that the Generating Facility is an Existing Qualifying Cogeneration Facility.

9.02

Additional Covenants by Seller. Seller covenants to Buyer that:

(a)

It will have Site Control as of the earlier of (i) the Term Start Date and (ii) any period before the Term Start Date to the extent necessary for Seller to perform its obligations under this Agreement and, in each case, will maintain Site Control throughout the Term;

(b)

Throughout the Term, it or its subcontractors will own or lease and Operate the Generating Facility unless otherwise agreed to by the Parties;

(c)

Throughout the Term, it will deliver the Product to Buyer free and clear of all liens, security interests, Claims and encumbrances or any interest therein or thereto by any Person;

(d)

Throughout the Term, it will hold the rights to all of the Product, subject to the terms of this Agreement;

(e)

From the Effective Date until the Term End Date, the Generating Facility will maintain its status as a Qualifying Cogeneration Facility, subject to Section 3.17(c);

(f)

Throughout the Term, it will not (1) convey, transfer, allocate, designate, award, report or otherwise provide any or all of the Product, or any portion thereof, or any benefits derived therefrom, to any party other than Buyer (except, if Buyer is not Scheduling Coordinator, as may relate to transactions in the Real-Time Market arising from ordinary course deviations between Metered Energy and electric energy Scheduled to Buyer), or (2) start-up or Operate the Generating Facility per instruction of or for the benefit of any third party (except in order to satisfy the Site Host Load, or as directed by the Scheduling Coordinator, CAISO or the Transmission Provider, or as required by other Applicable Laws); and

(g)

Seller shall comply with all (i) applicable cap-and-trade programs for the regulation of Greenhouse Gas, as established by any Governmental Authority pursuant to federal or state legislation, and (ii) other applicable programs regulating Greenhouse Gas emissions.

9.03

Indemnity.

(a)

Each Party as indemnitor shall defend, save harmless and indemnify the other Party and the directors, officers, employees, and agents of such other Party against and from any and all loss, liability, damage, claim, cost, charge, demand,

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or expense (including any direct, indirect, or consequential loss, liability, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees) for injury or death to Persons, including employees of either Party, and physical damage to property including property of either Party arising out of or in connection with the negligence or willful misconduct of the indemnitor relating to its obligations under this Agreement. This indemnity applies notwithstanding the active or passive negligence of the indemnitee. However, neither Party is indemnified under this Agreement for its loss, liability, damage, claim, cost, charge, demand or expense to the extent resulting from its negligence or willful misconduct. (b)

Each Party releases and shall defend, save harmless and indemnify the other Party from any and all loss, liability, damage, claim, cost, charge, demand or expense arising out of or in connection with any breach made by the indemnifying Party of its representations, warranties and covenants in Section 9.01 and Section 9.02.

(c)

The provisions of this Section 9.03 may not be construed to relieve any insurer of its obligations to pay any insurance Claims in accordance with the provisions of any valid insurance policy.

(d)

Notwithstanding anything to the contrary in this Agreement, if Seller fails to comply with the provisions of Section 9.10, Seller shall, at its own cost, defend, save harmless and indemnify Buyer, its directors, officers, employees, and agents, assigns, and successors in interest, from and against any and all loss, liability, damage, claim, cost, charge, demand, or expense of any kind or nature (including any direct, indirect, or consequential loss, damage, claim, cost, charge, demand, or expense, including reasonable attorneys’ fees and other costs of litigation), resulting from injury or death to any person or damage to any property, including the personnel or property of Buyer, to the extent that Buyer would have been protected had Seller complied with all of the provisions of Section 9.10. The inclusion of this Section 9.03(d) is not intended to create any express or implied right in Seller to elect not to provide the insurance required under Section 9.10.

(e)

Each Party shall defend, save harmless and indemnify the other Party against any Governmental Charges for which such indemnifying Party is responsible under Article Eight.

(f)

Seller shall defend, save harmless and indemnify Buyer against any increase in GHG Compliance Costs and other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to Seller or the Generating Facility to the extent that such GHG Compliance Costs or other costs result from

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Seller’s modification or repowering of the Generating Facility in accordance with Section 3.07. (g)

Seller shall defend, save harmless and indemnify Buyer against any penalty imposed upon Buyer as a result of Seller’s failure to fulfill its obligations regarding Resource Adequacy Benefits as set forth in Sections 3.01 and 3.02, with the exception of the obligations set forth in Section 3.01(c)(vi).

(h)

Seller is solely responsible for any NERC Standards Non-Compliance Penalties arising from or relating to Seller’s failure to perform the Generator Operator Obligations or the Generator Owner Obligations for which Seller is responsible, in accordance with Section 3.21, and will indemnify, defend and hold Buyer harmless from and against all liabilities, damages, Claims, losses, and reasonable costs and expenses (which shall include reasonable costs and expenses of outside or in-house counsel) incurred by Buyer arising from or relating to Seller’s actions or inactions that result in NERC Standards Non-Compliance Penalties or an attempt by any Governmental Authority, Person to assess such NERC Standards Non-Compliance Penalties against Buyer. Buyer will indemnify, defend and hold Seller harmless from and against all liabilities, damages, Claims, losses and reasonable costs and expenses (which shall include reasonable costs of outside and in-house counsel) incurred by Seller for any NERC Standards NonCompliance Penalties to the extent they are due to Buyer’s negligence or willful misconduct in performing its role as Seller’s Scheduling Coordinator during the Term.

(i)

All indemnity rights will survive the termination of this Agreement for 12 months.

9.04

Assignment.

(a)

With Consent. Subject to Section 9.04(b), Seller may not transfer or assign this Agreement or its rights under this Agreement without the prior written consent of Buyer, which consent may not be unreasonably withheld or delayed. Any direct or indirect change of control of Seller (whether voluntary or by operation of law) will be deemed an assignment and will require the prior written consent of Buyer, which consent will not be unreasonably withheld. For purposes of this Section 9.04, Buyer will not withhold its consent to an indirect change of control of Seller if Seller demonstrates to Buyer’s reasonable satisfaction that Seller shall continue to perform its obligations under this Agreement as if no such indirect change of control had occurred.

(b)

Without Consent. Notwithstanding anything to the contrary set forth in Section 9.04(a):

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(i)

Seller may, without the consent of Buyer (and without relieving itself from liability hereunder): (1) transfer, sell, pledge, encumber or assign this Agreement or the accounts, revenues or proceeds hereof in connection with any financing or other financial arrangements in accordance with Section 9.05; or (2) transfer or assign this Agreement to ana Related Entity of Seller, which Related Entity’s creditworthiness is equal to or higher than that of Seller; and

(ii)

Seller does not need to obtain Buyer’s consent to any change of control described in this Section 9.04 if such change of control results from a purchase of the outstanding shares of a publicly traded company.

9.05

Consent to Collateral Assignment. Subject to the provisions of this Section 9.05, Seller may (but is not obligated to) assign this Agreement as collateral to a Lender for any financing or refinancing of the Generating Facility, including a SaleLeaseback Transaction or Equity Investment and, in connection therewith, Buyer shall in good faith work with Seller and Lender to agree upon a consent to a collateral assignment of this Agreement or to a Sale-Leaseback Transaction or Equity Investment, as applicable (“Collateral Assignment Agreement”).

The Collateral Assignment Agreement shall be in form and substance reasonably agreed to by Buyer, Seller and Lender, and shall include, among others, the following provisions (together with such other commercially reasonable provisions required by any Lender that are reasonably acceptable to Buyer): (a)

Buyer shall give, to the Person(s) to be specified by Lender in the Collateral Assignment Agreement, simultaneously with the Notice to Seller and before exercising its right to terminate this Agreement, written Notice of any event or circumstance known to Buyer which would, if not cured within the applicable cure period specified in Article VI, constitute an Event of Default (an “Incipient Event of Default”);

(b)

Lender shall have the right to cure an Incipient Event of Default or an Event of Default by Seller in accordance with the same provisions of this Agreement as apply to Seller;

(c)

Article Nine

Following an Event of Default by Seller under this Agreement, Buyer may require Seller to (although Lender may, but shall have no obligation, subject to 9.05(g)) provide to Buyer a report concerning: (i)

The status of efforts by Seller or Lender to develop a plan to cure the Event of Default;

(ii)

Impediments to the cure plan or its development;

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(iii)

If a cure plan has been adopted, the status of the cure plan’s implementation (including any modifications to the plan as well as the expected timeframe within which any cure is expected to be implemented); and

(iv)

Any other information which Buyer may reasonably require related to the development, implementation and timetable of the cure plan;

(d)

Seller or Lender shall provide the report to Buyer within 10 Business Days after Notice from Buyer requesting the report. Buyer shall have no further right to require the report with respect to a particular Event of Default after that Event of Default has been cured;

(e)

Lender shall have the right to cure an Event of Default or Incipient Event of Default on behalf of Seller, only if Lender sends a written notice to Buyer before the end of any cure period indicating Lender’s intention to cure. Lender may remedy or cure the Event of Default or Incipient Event of Default within the cure period under this Agreement. Such cure period for Lender shall be extended for each day Buyer does not provide the Notice to Lender referred to in Section 9.05(a). In addition, such cure period may, in Buyer’s reasonable discretion, be extended by no more than an additional 180 days. If possession of the Generating Facility is necessary to cure such Incipient Event of Default or Event of Default, Lender has commenced foreclosure proceedings within 60 days after receipt of such Notice from Buyer, and Lender is making diligent and consistent efforts to complete such foreclosure, take possession of the Generating Facility and promptly cure the Incipient Event of Default or Event of Default, Lender or its designee(s) or assignee(s) will be allowed a reasonable period of time to complete such foreclosure proceedings, take possession of the Generating Facility and cure such Incipient Event of Default or Event of Default, not to exceed 180 days after Lender’s commencement of foreclosure. Additionally, if Lender is prohibited from curing any Incipient Event of Default or Event of Default by any process, stay or injunction issued by a Governmental Authority or pursuant to any bankruptcy, insolvency or similar proceedings, then the time period for curing such Incipient Event of Default or Event of Default shall be extended for the period of the prohibition provided that Lender is exercising reasonable diligence in having such process, stay or injunction removed;

(f)

Lender shall have the right to consent before any termination of this Agreement which does not arise out of an Event of Default or the end of the Term;

(g)

Lender shall receive prior Notice of, and shall have the right to approve material amendments to this Agreement, which approval may not be unreasonably withheld, delayed or conditioned;

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(h)

In the event Lender, directly or indirectly, takes title to the Generating Facility (including title by foreclosure or deed in lieu of foreclosure), the Person taking title to the Generating Facility shall assume all of Seller’s obligations arising under this Agreement and all related agreements (subject to such limits on liability as are mutually agreed to by Seller, Buyer and Lender as set forth in the Collateral Assignment Agreement); provided, however, that Lender (or such Person) shall have no liability for any monetary obligations of Seller under this Agreement which are due and owing to Buyer as of the assumption date (but this provision may not be interpreted to limit Buyer’s rights to proceed against Seller as a result of an Event of Default) and Lender’s (or such Person’s) liability to Buyer after such assumption shall be limited to its interest in the Generating Facility; provided further, that before such assumption, if Buyer advises Lender (or such Person) that Buyer will require that Lender (or such Person) cure (or cause to be cured) one or more monetary or non-monetary Incipient Event(s) of Default or Event(s) of Default existing as of the date such Person takes title in order to avoid the exercise by Buyer (in its sole discretion) of Buyer’s right to terminate this Agreement with respect to such Incipient Event(s) of Default or Event(s) of Default, then Lender (or such Person) at its option and in its sole discretion may elect to either (i) cause such Incipient Event(s) of Default or Event of Default to be cured, or (ii) not assume this Agreement;

(i)

If Lender has assumed this Agreement as provided in Section 9.05(h) and elects to sell or transfer the Generating Facility (after Lender directly or indirectly, takes title to the Generating Facility), or sale of the Generating Facility occurs through the actions of Lender or an agent of or representative of Lender (excluding any foreclosure sale where a third party other than Lender, Seller, an Related Entity of Lender or an Related Entity of Seller is the buyer), then Lender must cause the transferee or buyer to assume all of Seller’s obligations arising under this Agreement and all related agreements as a condition of the sale or transfer excluding, however, a foreclosure (unless the transferee or buyer is Lender, Seller, an Related Entity of Lender or an Related Entity of Seller). Lender shall be released from all further obligations under the Agreement and all related documents following such assumption. Such sale or transfer (excluding a foreclosure) may be made only to a Person reasonably acceptable to Buyer; and

(j)

If this Agreement is rejected in Seller’s Bankruptcy or otherwise terminated in connection therewith and if Lender or its representative or designee, directly or indirectly, takes title to the Generating Facility, then, at the request of either Buyer or Lender, Buyer and Lender (or its designee or representative) shall promptly enter into a new agreement with Buyer having substantially the same terms as this Agreement for the term that would have been remaining under this Agreement, provided that Lender’s (or its designee’s or representative’s) liability under such new agreement shall be limited to its interest in the Generating

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Facility and neither Lender (or its designee or representative) nor Buyer shall have any personal liability to the other for any amounts owing and neither Buyer nor Lender (or its designee or representative) shall have any obligation to cure any defaults under the original Agreement that was rejected in, or otherwise terminated in connection with Seller’s Bankruptcy. 9.06

Governing Law and Jury Trial Waiver. THIS AGREEMENT AND THE RIGHTS AND DUTIES OF THE PARTIES HEREUNDER ARE GOVERNED BY AND CONSTRUED, ENFORCED AND PERFORMED IN ACCORDANCE WITH THE LAWS OF THE STATE OF CALIFORNIA, WITHOUT REGARD TO PRINCIPLES OF CONFLICTS OF LAW. TO THE EXTENT ENFORCEABLE AT SUCH TIME, EACH PARTY WAIVES ITS RESPECTIVE RIGHT TO ANY JURY TRIAL WITH RESPECT TO ANY LITIGATION ARISING UNDER OR IN CONNECTION WITH THIS AGREEMENT.

9.07

Notices. All Notices shall be provided as specified in Exhibit N. Notices (other than Forecasts and Scheduling requests) shall, unless otherwise specified in this Agreement, be in writing and may be delivered by hand delivery, first class United States mail, overnight courier service, electronic transmission or facsimile. Notices provided in accordance with this Section 9.07 are deemed given as follows:

(a)

Notice by facsimile, electronic transmission or hand delivery is deemed given at the close of business on the day actually received, if received during business hours on a Business Day, and otherwise are deemed given at the close of business on the next Business Day;

(b)

Notice by overnight first class United States mail or overnight courier service is deemed given on the next Business Day after such Notice is sent out;

(c)

Notice by first class United States mail is deemed given two Business Days after the postmarked date;

(d)

Notices are effective on the date deemed given, unless a different date for the Notice to go into effect is stated in another section of this Agreement;

(e)

A Party may change its designated representatives, addresses and other contact information by providing Notice of same in accordance herewith; and

(f)

All Notices for this Generating Facility must reference the identification number set forth on the cover page of this Agreement.

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9.08

General.

(a)

This Agreement supersedes all prior agreements, whether written or oral, between the Parties with respect to its subject matter and constitutes the entire agreement between the Parties relating to its subject matter.

(b)

This Agreement will not be construed against any Party as a result of the preparation, substitution, submission or other event of negotiation, drafting or execution hereof.

(c)

Except to the extent provided for in this Agreement, no amendment or modification to this Agreement is enforceable unless reduced to a writing signed by all Parties.

(d)

If any provision of this Agreement is held invalid or unenforceable by any court of competent jurisdiction, the other provisions of this Agreement will remain in full force and effect. Any provision of this Agreement held invalid or unenforceable only in part or degree will remain in full force and effect to the extent not held invalid or unenforceable.

(e)

Waiver by a Party of any default by the other Party will not be construed as a waiver of any other default.

(f)

The term “including” when used in this Agreement is by way of example only and will not be considered in any way to be in limitation.

(g)

The word “or” when used in this Agreement includes the meaning “and/or” unless the context unambiguously dictates otherwise.

(h)

The headings used in this Agreement are for convenience and reference purposes only and will not affect its construction or interpretation. All references to “Articles”, “Sections” and “Exhibits” refer to the corresponding Articles, Sections and Exhibits of this Agreement. Unless otherwise specified, all references to “Articles” or “Sections” in Exhibits A through T refer to the corresponding Articles and Sections in the main body of this Agreement. Words having wellknown technical or industry meanings have such meanings unless otherwise specifically defined in this Agreement.

(i)

Where days are not specifically designated as Business Days, they are calendar days. Where years are not specifically designated as Term Years, they are calendar years.

(j)

This Agreement will apply to, be binding in all respects upon and inure to the benefit of the successors and permitted assigns of the Parties. Nothing in this

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Agreement will be construed to give any Person other than the Parties any legal or equitable right, remedy or claim under or with respect to this Agreement or any provision of this Agreement, except as shall inure to a successor or permitted assignee. (k)

No provision of this Agreement is intended to contradict or supersede any applicable agreement between the Parties or between or among Seller, the CAISO and the Transmission Provider, covering transmission, distribution, metering, scheduling or interconnection of electric energy (including the PGA and QF PGA). In the event of an apparent contradiction between this Agreement and any such agreement, the applicable agreement controls.

(l)

Whenever this Agreement specifically refers to any law, tariff, government department or agency, regional reliability council, Transmission Provider, or credit rating agency, the Parties agree that the reference also refers to any successor to such law, tariff or organization.

(m)

The Parties acknowledge and agree that this Agreement and the transactions contemplated by this Agreement constitute a “forward contract” within the meaning of the United States Bankruptcy Code and that Buyer and Seller are each “forward contract merchants” within the meaning of the United States Bankruptcy Code.

(n)

This Agreement may be executed in one or more counterparts, each of which will be deemed to be an original of this Agreement and all of which, when taken together, will be deemed to constitute one and the same agreement. The exchange of copies of this Agreement and of signature pages by facsimile transmission, an Adobe Acrobat file or by other electronic means constitutes effective execution and delivery of this Agreement as to the Parties and may be used in lieu of the original Agreement for all purposes. Signatures of the Parties transmitted by facsimile or by other electronic means will be deemed to be their original signatures for all purposes.

(o)

The Parties acknowledge that neither Party is waiving any right it may have under the Settlement Agreement.

9.09

Confidentiality.

(a)

Neither Party may disclose any Confidential Information to a third party, other than:

(i)

To such Party’s employees, Lenders, investors, attorneys, accountants or advisors who have a need to know such information and have agreed to keep such terms confidential;

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(ii)

To potential Lenders with the consent of Buyer, which consent will not be unreasonably withheld; provided, however, that disclosure (1) of cash flow and other financial projections to any potential Lender or investor in connection with a potential loan or tax equity investment; or (2) to potential Lenders or investors with whom Seller has negotiated (but not necessarily executed) a term sheet or other similar written mutual understanding, will not require such consent of Buyer; provided further, that in each case such potential Lender or investor has a need to know such information and has agreed to keep such terms confidential;

(iii)

To Buyer’s Procurement Review Group, as defined in D.02-08-071, or Buyer’s Cost Allocation Mechanism Group, as defined in D.06-07-029 and D.08-09-012, and pursuant to the Settlement Agreement and related Decisions, subject to a protective order applicable to Buyer’s Procurement Review Group; or Buyer’s Cost Allocation Mechanism Group;

(iv)

With respect to Confidential Information other than nonpublic financial information of Seller supplied to Buyer pursuant to Section 3.20, to the CPUC, the CEC or the FERC, under seal for any regulatory purpose, including policymaking, but only provided that the confidentiality protections from the CPUC under Section 583 of the California Public Utilities Code or other statute, order or rule offering comparable confidentiality protection are in place before the communication of such Confidential Information;

(v)

In order to comply with any Applicable Law or any exchange, Control Area or CAISO rule, or order issued by a court or entity with competent jurisdiction over the disclosing party, other than to those entities set forth in Section 9.09(a)(vi);

(vi)

In order to comply with any Applicable Law, including applicable regulation, rule, subpoena, or order of the CPUC, CEC, FERC, any court, administrative agency, legislative body or other tribunal, or any discovery or data request of the CPUC;

(vii)

To representatives of a Party’s credit ratings agencies who have a need to review the terms and conditions of this Agreement for the purpose of assisting the Party in evaluating this Agreement for credit rating purposes or with respect to the potential impact of this Agreement on the Party’s financial reporting obligations, in each case subject to confidentiality restrictions no less stringent than as set forth in this Agreement; and

(viii) As may reasonably be required to participate in WREGIS or other process recognized under Applicable Laws for the registration, transfer or ownership of Green Attributes associated with the Related Products.

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(b)

In connection with requirements, requests or orders to produce documents or information in the circumstances provided in Sections 8.03 and 9.09(a)(vi) (“Disclosure Order”) each Party shall, to the extent practicable, use reasonable efforts to (i) notify the other Party before disclosing the confidential information, and (ii) prevent or limit such disclosure. After using such reasonable efforts, the disclosing party may not be (x) prohibited from complying with a Disclosure Order, or (y) liable to the other Party for monetary or other damages incurred in connection with the disclosure of any terms or conditions of this Agreement which are the subject of such Disclosure Order.

(c)

Except as provided in clause (y) of Section 9.09(b), the Parties are entitled to all remedies available at law or in equity to enforce, or seek relief in connection with, the confidentiality obligations set forth in this Section 9.09.

9.10

Insurance.

(a)

As of the Effective Date and throughout the Term (and for such additional periods as may be specified in this Section 9.10), Seller shall, at its own expense, provide and maintain in effect the insurance policies and minimum limits of coverage specified in this Section 9.10, and such additional coverage as may be required by Applicable Law, with insurance companies which are authorized to do business in the state in which the services are to be performed and which have an A.M. Best’s Insurance Rating of not less than A-:VII. The minimum insurance requirements specified in this Section 9.10 do not in any way limit or relieve Seller of any obligation assumed elsewhere in this Agreement, including, but not limited to, Seller’s defense and indemnity obligations.

(i)

Workers’ Compensation Insurance with the statutory limits required by the state having jurisdiction over Seller’s employees;

(ii)

Employer’s Liability Insurance with limits of not less than:

1)

Bodily injury by accident – One Million dollars ($1,000,000) each accident;

2)

Bodily injury by disease – One Million dollars ($1,000,000) policy limit; and

3)

Bodily injury by disease – One Million dollars ($1,000,000) each employee; and

(iii)

Commercial General Liability Insurance, (which, except with the prior written consent of Buyer and subject to Sections 9.10(a)(ii)(1) and (2), shall be written on an “occurrence,” not a “claims-made” basis), covering all operations by or on behalf of Seller arising out of or connected with this Agreement, including coverage for bodily injury, broad form property damage, personal and advertising injury, products/completed operations, and contractual liability. Such insurance shall bear a combined single limit per occurrence and annual aggregate of not less than one million dollars ($1,000,000), exclusive of defense costs, for all

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coverages. Such insurance shall contain standard cross-liability and severability of interest provisions. If Seller elects, with Buyer’s written concurrence, to use a “claims made” form of Commercial General Liability Insurance, then the following additional requirements apply: 1) The retroactive date of the policy must be prior to the Effective Date; and 2) Either the coverage must be maintained for a period of not less than four years after the Agreement terminates, or the policy must provide for a supplemental extended reporting period of not less than four years after the Agreement terminates. (iv)

Commercial Automobile Liability Insurance covering bodily injury and property damage with a combined single limit of not less than $1,000,000 per occurrence. Such insurance shall cover liability arising out of Seller’s use of all owned (if any), non-owned and hired automobiles in the performance of the Agreement.

(v)

Umbrella/Excess Liability Insurance, written on an “occurrence,” not a “claimsmade” basis, providing coverage excess of the underlying Employer’s Liability, Commercial General Liability, and Commercial Automobile Liability insurance, on terms at least as broad as the underlying coverage, with limits of not less than $10,000,000 per occurrence and in the annual aggregate. The insurance requirements of this Section 9.10 can be provided by any combination of Seller’s primary and excess liability policies.

(b)

The insurance required in Section 9.10(a) apply as primary insurance to, without a right of contribution from, any other insurance maintained by or afforded to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, and employees, regardless of any conflicting provision in Seller's policies to the contrary. To the extent permitted by Applicable Law, Seller and its insurers are required to waive all rights of recovery from or subrogation against Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, employees and insurers. The Commercial General Liability and Umbrella/Excess Liability insurance required above shall name Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents and employees, as additional insureds for liability arising out of Seller’s construction, ownership or Operation of the Generating Facility.

(c)

At the time this Agreement is executed, or within a reasonable time thereafter, and within a reasonable time after coverage is renewed or replaced, Seller shall furnish to Buyer certificates of insurance evidencing the coverage required in this Section 9.10, written on forms and with deductibles reasonably acceptable to Buyer. All deductibles, co-insurance and self-insured retentions applicable to the insurance above shall be paid by Seller. All certificates of insurance shall note that the insurers issuing coverage shall endeavor to provide Buyer with at least 30

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

days’ prior written notice in the event of cancellation of coverage. Buyer’s receipt of certificates that do not comply with the requirements stated herein, or Seller’s failure to provide certificates, does not limit or relieve Seller of the duties and responsibility of maintaining insurance in compliance with the requirements in this Section 9.10 and does not constitute a waiver of any of the requirements in this Section 9.10. (d)

If Seller fails to comply with any of the provisions of this Section 9.10, Seller, among other things and without restricting Buyer’s remedies under the Applicable Law or otherwise, shall, at its own cost and expense, act as an insurer and provide insurance in accordance with the terms and conditions above. With respect to the required Commercial General Liability, Umbrella/Excess Liability and Commercial Automobile Liability insurance, Seller shall provide a current, full and complete defense to Buyer, its subsidiaries and affiliates, and their respective officers, directors, shareholders, agents, employees, assigns, and successors in interest, in response to a third party claim in the same manner that an insurer would have, had the insurance been maintained in accordance with the terms and conditions set forth above.

(e)

Seller has the right to self-insure to comply with Seller’s obligations under this Section 9.10. The insurance carrier or carriers and form of policy (including any deductible amount), or any plan for self-insurance shall be subject to review and approval by Buyer, which approval may not be unreasonably withheld, conditioned or delayed.

9.11

Nondedication. Notwithstanding any other provisions of this Agreement, neither Party dedicates any of the rights that are or may be derived from this Agreement or any part of its facilities involved in the performance of this Agreement to the public or to the service provided under this Agreement, and such service shall cease upon termination of this Agreement.

9.12

Mobile Sierra. Notwithstanding any provision of this Agreement, neither Party will seek, nor will they support any third party in seeking, to prospectively or retroactively revise the rates, terms, or conditions of service of this Agreement through application or complaint to FERC pursuant to the provisions of Section 205, 206, or 306 of the Federal Power Act, or any other provisions of the Federal Power Act, absent prior written agreement of the Parties.

Further, absent the prior agreement in writing by both Parties, the standard of review for changes to the rates, terms or conditions of service of this Agreement proposed by a Party, a non-Party or the FERC acting sua sponte shall be the “public interest” standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 US 332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 US 348 (1956).

Article Nine

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9.13

Seller Ownership and Control of Generating Facility. Seller agrees, that, in accordance with FERC Order No. 697, upon request of Buyer, Seller shall submit a letter of concurrence in support of an affirmative statement by Buyer that the contractual arrangement set forth in this Agreement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR Section 35.42. Seller also agrees that it will not, in filings, if any, made subject to Order Nos. 652 and 697, claim that the contractual arrangement set forth in this Agreement conveys ownership or control of generation capacity from Seller to Buyer.

9.14

Simple Interest Payments. Except as specifically provided in this Agreement, any outstanding and past due amounts owing and unpaid by either Party under the terms of this Agreement shall be eligible to receive a Simple Interest Payment calculated using the Interest Rate for the number of days between the date due and the date paid.

9.15

Payments. Payments to be made under this Agreement shall be made, at Seller’s option, by check or electronic wire funds transfer.

9.16

Provisional Relief. The Parties acknowledge and agree that irreparable damage would occur if certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or the other security, to seek a preliminary injunction, temporary restraining order, or other provisional relief as a remedy for a breach of Sections 3.01, 3.02, 3.03, or 9.09 in any court of competent jurisdiction, notwithstanding the obligation to submit all other disputes (including all Claims for monetary damages under this Agreement) to arbitration pursuant to Section 10.01. The Parties further acknowledge and agree that the results of such arbitration may be rendered ineffectual without such provisional relief.

Such a request for provisional relief does not waive a Party’s right to seek other remedies for the breach of the provisions specified above in accordance with Section 10.01, notwithstanding any prohibition against claim-splitting or other similar doctrine. The other remedies that may be sought include specific performance and injunctive or other equitable relief, plus any other remedy specified in this Agreement for such breach of the provision, or if this Agreement does not specify a remedy for such breach, all other remedies available at law or equity to the Parties for such breach. *** End of Article Nine ***

Article Nine

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ARTICLE TEN.

DISPUTE RESOLUTION

10.01 Dispute Resolution. Other than requests for provisional relief under Section 9.16, any and all disputes, Claims or controversies arising out of, relating to, concerning, or pertaining to the terms of this Agreement, or to either Party’s performance or failure of performance under this Agreement (“Disputes”), which Disputes the Parties have been unable to resolve by informal methods, will first be submitted to mediation in accordance with the procedures described in Section 10.02, and if the Dispute is not resolved through mediation, then for final and binding arbitration in accordance with the procedures described in Section 10.03. 10.02 Mediation. Either Party may initiate mediation by providing Notice to the other Party of a written request for mediation, setting forth a description of the Dispute and the relief requested. The Parties will cooperate with one another in selecting the mediator (“Mediator”) from the panel of neutrals from JAMS or any other mutually acceptable non-JAMS Mediator, and in scheduling the time and place of the mediation. Such selection and scheduling will be completed within 45 days after Notice of the request for mediation. Unless otherwise agreed to by the Parties, the mediation will not be scheduled for a date that is greater than 120 days from the date of Notice of the request for mediation. The Parties covenant that they will participate in the mediation, and that they will share equally in its costs (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the mediation, which fees and costs will be borne by such Party). All offers, promises, conduct and statements, whether oral or written, made in connection with or during the mediation by either of the Parties, their agents, representatives, employees, experts and attorneys, and by the Mediator or any of the Mediator’s agents, representatives and employees, will not be subject to discovery and will be confidential, privileged and inadmissible for any purpose, including impeachment, in any arbitration or other proceeding between or involving the Parties, or either of them; provided, however, that evidence that is otherwise admissible or discoverable will not be rendered inadmissible or non-discoverable as a result of its use in the mediation. 10.03 Arbitration. Either Party may initiate binding arbitration with respect to the matters first submitted to mediation in accordance with Section 10.02 by providing Notice of a demand for binding arbitration before a single, neutral arbitrator (the “Arbitrator”) at any time following the unsuccessful conclusion of the mediation provided for in Section 10.02.

Article Ten

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The Parties will cooperate with one another in selecting the Arbitrator within 60 days after Notice of the demand for arbitration and will further cooperate in scheduling the arbitration to commence no later than 180 days from the date of Notice of the demand. If the Parties are unable to agree upon a mutually acceptable Arbitrator, the Arbitrator will be appointed as provided for in California Code of Civil Procedure Section 1281.6. To be qualified as an Arbitrator, each candidate must be a retired judge of a trial court of any state or federal court, or retired justice of any appellate or supreme court. Unless otherwise agreed to by the Parties, the individual acting as the Mediator will be disqualified from serving as the Arbitrator in the dispute, although the Arbitrator may be another member of the JAMS panel of neutrals or such other panel of neutrals from which the Parties have agreed to select the Mediator. Upon Notice of a Party’s demand for binding arbitration, such Dispute submitted to arbitration, including the determination of the scope or applicability of this Agreement to arbitrate, will be determined by binding arbitration before the Arbitrator, in accordance with the laws of the State of California, without regard to principles of conflicts of laws. Except as provided for in this Section 10.03, the arbitration will be conducted by the Arbitrator in accordance with the rules and procedures for arbitration of complex business disputes for the organization with which the Arbitrator is associated. Absent the existence of such rules and procedures, the arbitration will be conducted in accordance with the California Arbitration Act, California Code of Civil Procedure Section 1280 et seq. and California procedural law (including the Code of Civil Procedure, Civil Code, Evidence Code and Rules of Court, but excluding local rules). Notwithstanding the rules and procedures that would otherwise apply to the arbitration, and unless the Parties agree to a different arrangement, the place of the arbitration will be in Los Angeles, California, and discovery will be limited as follows: (a)

Before discovery commences, the Parties shall exchange an initial disclosure of all documents and percipient witnesses which they intend to rely upon or use at any arbitration proceeding (except for documents and witnesses to be used solely for impeachment);

(b)

The initial disclosure will occur within 30 days after the initial conference with the Arbitrator or at such time as the Arbitrator may order;

(c)

Discovery may commence at any time after the Parties’ initial disclosure;

(d)

The Parties will not be permitted to propound any interrogatories or requests for admissions;

Article Ten

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(e)

Discovery will be limited to 25 document requests (with no subparts), three lay witness depositions, and three expert witness depositions (unless the Arbitrator holds otherwise following a showing by the Party seeking the additional documents or depositions that the documents or depositions are critical for a fair resolution of the Dispute or that a Party has improperly withheld documents);

(f)

Each Party is allowed a maximum of three expert witnesses, excluding rebuttal experts;

(g)

Within 60 days after the initial disclosure, or at such other time as the Arbitrator may order, the Parties shall exchange a list of all experts upon which they intend to rely at the arbitration proceeding;

(h)

Within 30 days after the initial expert disclosure, the Parties may designate a maximum of two rebuttal experts;

(i)

Unless the Parties agree otherwise, all direct testimony will be in form of affidavits or declarations under penalty of perjury; and

(j)

Each Party shall make available for cross-examination at the arbitration hearing its witnesses whose direct testimony has been so submitted.

Subject to Article Seven, the Arbitrator will have the authority to grant any form of equitable or legal relief a Party might recover in a court action. The Parties acknowledge and agree that irreparable damage would occur in the event certain provisions of this Agreement are not performed in accordance with the terms hereof, that money damages would not be a sufficient remedy for any breach of such provisions of this Agreement, and that the Parties shall be entitled, without the requirement of posting a bond or other security, to specific performance and injunctive or other equitable relief as a remedy for a breach of Sections 3.01, 3.02, 3.03 or 9.09. Judgment on the award may be entered in any court having jurisdiction. The Arbitrator must, in any award, allocate all of the costs of the binding arbitration (other than each Party’s individual attorneys’ fees and costs related to the Party’s participation in the arbitration, which fees and costs will be borne by such Party), including the fees of the Arbitrator and any expert witnesses, against the Party who did not prevail. Until such award is made, however, the Parties will share equally in paying the costs of the arbitration. *** End of Article Ten ***

Article Ten

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IN WITNESS WHEREOF, the Parties have caused this Agreement to be duly executed by their respective authorized representatives as of the Effective Date.

[SELLER’S NAME]SYCAMORE COGENERATION COMPANY,

SOUTHERN CALIFORNIA EDISON COMPANY,

a [Seller’s business registration] California general partnership

a California corporation

By:_____________________________ Name:________________________ Neil Burgess Title:_________________________ Executive Director

By:_____________________________ Name:________________________ Marc Ulrich Title:_________________________ Vice President, Renewable and Alternative Power

The contents of this document are subject to restrictions on disclosure as set forth herein. Signatures

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EXHIBIT A Definitions For purposes of this Agreement, the following terms and variations thereof have the meanings specified or referred to in this Exhibit A: “Actual HR” means the Heat Rate that must be used in accordance with and subject to the terms set forth in Section 2(a)(ii) of Exhibit S, which Heat Rate Buyer shall calculate, on the date of the commencement of the First Compliance Period, using the following formula: Actual HRn = The average of the Daily HRn for each delivery or flow date in the two (2) year period immediately preceding the commencement of the First Compliance Period Where: Daily HRn = [EPn – VOMn] / [GPn + GTn] Where: EPn = The average of the Day-Ahead hourly electric energy prices, as determined by the Integrated Forward Market (as defined in the CAISO Tariff) for (i) SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor, if Buyer is SCE or SDG&E, and (ii) NP15 Existing Zone Generation Trading Hub (formerly known as NP15), or its successor, if Buyer is PG&E; VOMn = Calendar month avoided variable O&M for the applicable month ($/kWh), per the Decision and CPUC Resolution E-4246; GPn = The applicable daily gas price index, which is (i) Platt’s Gas Daily (currently SoCalGas gas indices), if Buyer is SCE or SDG&E, or (ii) Platt’s Gas Daily (currently SoCalGas and PG&E Malin gas indices), if Buyer is PG&E; and GTn = The gas transportation rate for the applicable month, per CPUC Resolution E-4246. “Additional GHG Documentation” means the documentation necessary to allocate Free Allowances to electric energy delivered by Seller to Buyer, which documentation consists of the following, in each case for the time-period to which the Free Allowances are to apply: (a) the total amount of GHG emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, the Useful Thermal Energy Output of the Generating Facility, and the electric energy delivered to Buyer; (b) the Useful Thermal Energy Output of the Generating Facility; (c) the total electric energy produced by the Generating Facility, the electric energy

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

used to the serve the Site Host Load, and the electric energy delivered to Buyer; and (d) total fuel usage of the Generating Facility. “Agreement” has the meaning set forth in the Preamble. “Allowance” means a limited tradable authorization (whether in the form of a credit, allowance or other similar right), allocated to, issued to or purchased by, Seller, the Site Host or ana Related Entity of Seller, with respect to the Generating Facility, to emit one MT of Greenhouse Gas, in accordance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), and as applied to the Greenhouse Gas emitted by the Generating Facility. “Allowance Cost” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “Allowed Firm Energy” is determined in Section 3(l) of Exhibit D. “Allowed Hourly Energy”, or “E”, is determined in Section 3(f) of Exhibit D. “Allowed Payment Energy”, or “APE”, is determined in Section 2(c) of Exhibit D. “Ambient Outage” means reductions in capacity due to that status of, or variations in, Site Host Load or ambient weather conditions. “Annual GHG Reports” has the meaning set forth in Section 3(a) of Exhibit S. “Applicable HR” has the meaning set forth in Section 1 of Exhibit S. “Applicable Laws” means all constitutions, treaties, laws, ordinances, rules, regulations, interpretations, permits, judgments, decrees, injunctions, writs and orders of any Governmental Authority or arbitrator that apply to either or both of the Parties, the Generating Facility or the terms of this Agreement. “Arbitrator” has the meaning set forth in Section 10.03. “As-Available Capacity”, or “AAC”, is determined in Section 3(c) of Exhibit D. “As-Available Capacity Payment”, or “ACP”, is determined in Section 3(b) of Exhibit D. “As-Available Capacity Price” means the price adopted by the CPUC in the Decision and in subsequent rulings of the CPUC implementing the Decision, or pursuant to any such other formula as the CPUC may adopt from time to time for As-Available Capacity Payments to be made to Buyer’s Qualifying Cogeneration Facilities for the applicable year, as set forth in Section 3(b) of Exhibit D, in dollars per kW-year.

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“As-Available Contract Capacity” means the electric energy generating capacity that Seller provides on an as-available basis for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). “Availability Credit Factor”, or “ACF”, is determined in Section 3(i) of Exhibit D. “Availability Incentive Payments” has the meaning set forth in the CAISO Tariff. “Availability Penalty Factor”, or “APF”, is determined in Section 3(n) of Exhibit D. “Availability Standards” has the meaning set forth in the CAISO Tariff. “Bankrupt” means with respect to any Person, such Person: (a) Files a petition or otherwise commences, authorizes or acquiesces in the commencement of a proceeding or cause of action under any bankruptcy, insolvency, reorganization or similar law, or has any such petition filed or commenced against it (which petition is not dismissed within 90 days); (b) Makes an assignment or any general arrangement for the benefit of creditors; (c) Otherwise becomes bankrupt or insolvent (however evidenced); (d) Has a liquidator, administrator, receiver, trustee, conservator or similar official appointed with respect to it or any substantial portion of its property or assets; or (e) Is generally unable to pay its debts as they fall due. “Benchmark Capacity” is determined, as applicable, in Section 3(a) of Exhibit D-1, Section 3(a) of Exhibit D-2, and Section 9(a) of Exhibit E. “Burner Tip Gas Price” or “BTGP” has the meaning set forth in Section 1 of Exhibit S. “Business Day” means any day except a Saturday, Sunday, the Friday after the United States Thanksgiving holiday, or a Federal Reserve Bank holiday that begins at 8:00 a.m. and end at 5:00 p.m. local time for the Party sending a Notice or payment or performing a specified action. “Buyer” has the meaning set forth in the Preamble. “Buyer Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy produced by the Generating Facility. “Buyer Parent Energy Schedule” means the schedule of electric energy that Buyer establishes with the CAISO for electric energy delivered to the CAISO for the CAISO Global Resource ID associated with the Generating Facility. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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“Buyer Projected Energy Forecast” has the meaning set forth in Section 2(a) of Exhibit G. “CAISO” means the California Independent System Operator Corporation or successor entity that dispatches certain generating units, supplies certain loads and controls the transmission facilities of entities that (a) own, operate and maintain transmission lines and associated facilities or have entitlements to use certain transmission lines and associated facilities, and (b) have transferred to the CAISO or its successor entity operational control of such facilities or entitlements. “CAISO-Approved Meter” means any revenue quality, electric energy measurement meter furnished by Seller, that (a) is designed, manufactured and installed in accordance with the CAISO’s metering requirements, or, to the extent that the CAISO’s metering requirements do not apply, Prudent Electrical Practices, and (b) includes all of the associated metering transformers and related appurtenances that are required in order to measure the net electric energy output from the Generating Facility. “CAISO-Approved Quantity” means the total quantity of electric energy that Buyer Schedules with the CAISO and the CAISO approves in its final schedule which is published in accordance with the CAISO Tariff. “CAISO Charges” means the debits, costs, fees, penalties, sanctions, interest or similar charges, including imbalance energy charges, that are directly assigned by the CAISO to the CAISO Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement. “CAISO Charges Invoice” has the meaning set forth in Section 5 of Exhibit G. “CAISO Controlled Grid” has the meaning set forth in the CAISO Tariff. “CAISO Forced Outage Report” means a complete copy of a forced outage report in a form reasonably acceptable to Buyer which includes detailed information regarding the event, including the affected Generating Unit, outage start date and time, estimation of outage duration, MW unavailable and summary of work to be performed. “CAISO Global Resource ID” means the number or name assigned by the CAISO to the CAISOApproved Meter. “CAISO Revenues” means the credits, fees, payments, revenues, interest or similar benefits, including imbalance energy payments, that are directly assigned by the CAISO to the CAISO Global Resource ID for the Generating Facility for, or attributable to, Scheduling or deliveries from the Generating Facility under this Agreement.

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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“CAISO Tariff” means the California Independent System Operator Corporation Operating Agreement and Tariff, including the rules, protocols, procedures and standards attached thereto, as the same may be amended or modified from time to time and approved by the FERC. “Capacity Attributes” means any and all current or future defined characteristics, certificates, tag, credits, ancillary service attributes, or accounting constructs, howsoever entitled, other than Resource Adequacy Benefits, attributed to or associated with the electricity generating capability of the Generating Facility. “Capacity Credit Hours”, or “CCH”, is determined in Section 3(m) of Exhibit D. “Capacity Credit Period” is determined in Section 3(b)(iv) of Exhibit E. “Capacity Payment Allocation Factors”, or “CAF”, means the TOD Period factors which are used to calculate the TOD Period Capacity Payment, as set forth in the table in Section 3(a) of Exhibit D. “Capacity Performance Requirement”, or “CR”, means the values set forth in Section 1.04. “CARB” means California Air Resources Board, or any successor entity. “CARB Annual Report” has the meaning set forth in Section 3(a)(i) of Exhibit S. “CARB Mandatory GHG Emissions Annual Report” means the mandatory reporting regulations approved by CARB in December 2007, which became effective in January 2009, pursuant to the requirements set forth in the California Global Warming Solutions Act of 2006 for the reporting of Greenhouse Gas by major sources. “CEC” means the California Energy Commission, or any successor entity. “CFR” means the Code of Federal Regulations, as may be amended from time to time. “Check Meter” means the Buyer revenue-quality meter section or meter(s), which Buyer may require at its discretion, as set forth in Section 3.08(b) and will include those devices normally supplied by Buyer or Seller under the applicable utility Electric Service Requirements. “Claiming Party” has the meaning set forth in Section 5.02. “Claims” means all third party claims or actions, threatened or filed and, whether groundless, false, fraudulent or otherwise, that directly or indirectly relate to the subject matter of an indemnity, and the resulting losses, damages, expenses, attorneys’ fees and court costs, whether incurred by settlement or otherwise, and whether such claims or actions are threatened or filed before or after the termination of this Agreement. “Collateral Assignment Agreement” has the meaning set forth in Section 9.05. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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“Confidential Information” means all oral or written communications exchanged between the Parties on or after the Effective Date relating to the implementation of this Agreement, including information related to Seller’s compliance with operating and efficiency standards applicable to a “qualifying cogeneration facility” (as contemplated in 18 CFR Part 292, Section 292.205). Confidential Information does not include (i) information which is in the public domain as of the Effective Date or which comes into the public domain after the Effective Date from a source other than from the other Party, (ii) information which either Party can demonstrate in writing was already known to such Party on a non-confidential basis before the Effective Date, (iii) information which comes to a Party from a bona fide third-party source not under an obligation of confidentiality, or (iv) information which is independently developed by a Party without use of or reference to Confidential Information or information containing Confidential Information. “Control Area” means the electric power system (or combination of electric power systems) under the operational control of the CAISO or any other electric power system under the operational control of another organization vested with authority comparable to that of the CAISO. “Converted Physical Trade”, or “CPT”, means the quantity from Physical Trades, in MWh, that did not pass CAISO’s physical validation of the IFM. “Converted Physical Trade Price” means the price, in dollars per MWh, used by the CAISO to settle the quantity, in MWh, associated with the Converted Physical Trade. “Costs” means, with respect to the Non-Defaulting Party, brokerage fees, commissions, legal expenses and other similar third party transaction costs and expenses reasonably incurred by such Party in entering into any new arrangement which replaces this Agreement. “CPUC” means the California Public Utilities Commission, or any successor entity. “CPUC Approval” means a final and non-appealable order of the CPUC, without conditions or

modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement in their respective entirety, including payments to be made by Buyer, subject to CPUC review of Buyer’s administration of each of the Agreement, the Transition Tolling Confirmation, the Transition RA Confirmation and the Transition EEI Agreement. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. “Curtailment Period” means a time period for which Seller is requested by CAISO or a Transmission Provider to curtail its Power Product for Force Majeure or otherwise. “D.” has the meaning set forth in Recital A. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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“Day-Ahead” has the meaning set forth in the CAISO Tariff. “Day-Ahead Market” has the meaning set forth in the CAISO Tariff. “Day-Ahead Price” means the LMPQF, as set forth in Section 1 of Exhibit S. “Day-Ahead Schedule” has the meaning set forth in the CAISO Tariff. “Decision” has the meaning set forth in Recital A. “Defaulting Party” has the meaning set forth in Section 6.01(a). “Delivery Point” has the meaning set forth in Section 1.03. “Disclosure Order” has the meaning set forth in Section 9.09(b). “Dispute” has the meaning set forth in Section 10.01. “Early Termination Date” has the meaning set forth in Section 6.02(a). “Earned Capacity Hours”, or “ECH”, means the number of firm capacity equivalent available hours determined by dividing the Firm TOD Energy by the Firm Contract Capacity, as set forth in Section 3(j) of Exhibit D. “Effective Date” has the meaning set forth in the Preamble. “Emergency Condition” has the meaning set forth in the Transmission Provider’s LGIA or SGIA with Seller, or the distribution-level FERC-jurisdictional interconnection agreement with Seller, as applicable; provided, however, that if Seller interconnects pursuant to Tariff Rule 21, “Emergency Condition” means “Emergency”, as defined in such Tariff Rule 21. “Equitable Defense” means any Bankruptcy or other laws affecting creditors’ rights generally, and with regard to equitable remedies, the discretion of the court before which proceedings to obtain same may be pending. “Equity Investment” means an acquisition by a Lender of an ownership interest in the form of stock, membership or partnership interest of Seller or the immediate parent of Seller under which Seller retains the right to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s rights to enforce its ownership interest in Seller or the immediate parent of Seller, as applicable, in the event of a default by Seller or the immediate parent of Seller under Lender’s equity acquisition agreement or the partnership agreement, operating agreement, or other agreement governing the relationship between the equity owners of the Generating Facility. “Event of Default” has the meaning set forth in Section 6.01. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Existing PPA” has the meaning set forth in Section 1.01. “Existing Qualifying Cogeneration Facility” means a Generating Facility that commenced Parallel Operation before the Settlement Effective Date, and that, as of the Settlement Effective Date, (a) is a Qualifying Cogeneration Facility, and (b) is the generating facility under the Existing PPA. “Expected Term Year Energy Production” means the Metered Energy quantity expected to be produced by the Generating Facility during each Term Year, as set forth in Section 1.02(e). “Federal Funds Effective Rate” means the rate for that day opposite the caption “Federal Funds (effective)” as set forth in the weekly statistical release as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System. “FERC” means the Federal Energy Regulatory Commission, or any successor entity. “FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at market-based rates as such request is submitted to FERC by the Parties in accordance with Section 2.05 in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. “Financial Consolidation Requirement” has the meaning set forth in Section 3.20(a). “Financial Incentives” means any and all financial incentives, benefits or credits associated with the Generating Facility, or the ownership or Operation thereof, or the electrical or thermal output of the Generating Facility, including any production or investment tax credits, real or personal property tax credits or sales or use tax credits, but not including any Green Attributes, Capacity Attributes or Resource Adequacy Benefits. “Firm Capacity Payment”, or “FCP”, has the meaning set forth in Section 3(g) of Exhibit D. “Firm Capacity Price” or “CP” is set forth in Section 1.06(a), in dollars per kW-year. “Firm Contract Capacity”, or “FCC”, means the monthly generating capacity that Seller commits to have available at the Site for the Power Product, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Firm TOD Energy”, or “FE”, has the meaning set forth in Section 3(k) of Exhibit D. “First Compliance Period” means the first period of time for compliance with a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation). There will be no more than a single First Compliance Period. “First Penalty Month” has the meaning set forth in Section 3(b) of Exhibit I. “Floor Test Term” means the date that the First Compliance Period commences, for a period of three years. “Forced Outage” has the meaning set forth in the CAISO Tariff. “Force Majeure” means any event or circumstance to the extent beyond the control of, and not the result of the negligence of, or caused by, the Party seeking to have its performance obligation excused thereby, which by the exercise of due diligence such Party could not reasonably have been expected to avoid and which by exercise of due diligence it has been unable to overcome. Force Majeure does not include: (a) A failure of performance of any other Person, including any Person providing electric transmission service or fuel transportation to the Generating Facility, except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure event; (b) Failure to timely apply for or obtain Permits or other credits required to Operate the Generating Facility; (c) Breakage or malfunction of equipment (except to the extent that such failure was caused by an event that would otherwise qualify as a Force Majeure); or (d) A lack of fuel of an inherently intermittent nature such as wind, water, solar radiation or waste gas or waste derived fuel. “Force Majeure Credit Value”, or “FCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Force Majeure curtailment requested by Buyer, determined in accordance with Section 3 of Exhibit D-1. “Forecast” means the hourly forecast of (a) the total electric energy production of the Generating Facility (in MWh) when the Generating Facility is not PIRP-eligible or Buyer is not Scheduling Coordinator net of the Site Host Load and Station Use, or (b) the available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator net of the Site Host Load and Station Use. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 9

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Forward Settlement Amount” means the Non-Defaulting Party’s Costs and Losses on the one hand, netted against its Gains, on the other. If the Non-Defaulting Party’s Gains exceed its Costs and Losses, then the Forward Settlement Amount shall be zero dollars. If the Non-Defaulting Party’s Costs and Losses exceed its Gains, then the Forward Settlement Amount shall be an amount owing to the Non-Defaulting Party. The Forward Settlement Amount does not include consequential, incidental, punitive, exemplary or indirect or business interruption damages. “Free Allowance” means any Allowance freely allocated to Seller or the Generating Facility by CARB or an authorized Governmental Authority (or any entity authorized by such Governmental Authority). “Free Allowance Notice” means the Notice, delivered by Seller to Buyer in accordance with this Agreement, that sets forth the aggregate quantity of Free Allowances received by Seller during the applicable time-period and sets forth the allocation of such Free Allowances in accordance with the following: (i)

The allocation of Free Allowances by the CARB (or any other Governmental Authority) to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable time-period; or

(ii)

If the CARB (or any other Governmental Authority) does not allocate Free Allowances received by Seller as described in subsection (i) above, then Seller shall set forth in the Free Allowance Notice the quantity of Free Allowances allocated to the electric energy generated by the Generating Facility and delivered to Buyer during the applicable timeperiod (FAd) utilizing the following formula: FAd = FAt * [Ge/(Ge+ Gt)] * [Ed/(Esh + Ed)] Where: FAt = Total number of Free Allowances received by Seller with respect to the Generating Facility for the applicable time-period; Ge (in MTs) = Emissions of Greenhouse Gas attributed to the total amount of electric energy produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Gt (in MTs) = Emissions of Greenhouse Gas attributed to the Useful Thermal Energy Output produced by the Generating Facility for the applicable time-period (calculated in accordance with the formula set forth in Section 95112 of the

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 10

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

California Code of Regulations, or any successor thereto, which calculation must be set forth in the Free Allowance Notice); Ed (in kWh) = Electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period; and Esh (in kWh) = Electric energy generated by the Generating Facility and used to serve the Site Host Load for the applicable time-period; or (iii)

If the CARB (or any other Governmental Authority) does not allocate the Free Allowances received by Seller, as described in (i) above, and there is no available formula in any applicable rule or regulation for the calculation of Ge and Gt, as described in (ii) above, then Seller shall include in the Free Allowance Notice the total amount of emissions of Greenhouse Gas attributed to the electric energy period (Ge, in MTs) and the Useful Thermal Energy Output (Gt, in MTs) produced by the Generating Facility for the applicable time-period based on the two following formulas: Ge = G * (Useful Power Output / (Useful Power Output + Useful Thermal Energy Output)) Gt = G * (Useful Thermal Energy Output / (Useful Power Output + Useful Thermal Energy Output)) Where: G (in MTs) = Total emissions of Greenhouse Gas produced by the Generating Facility for the applicable time-period; Useful Power Output (in MMBtu) = As defined in 18 CFR §292.202(g), or any successor thereto; Useful Thermal Energy Output (in MMBtu) = As defined in 18 CFR §292.202(h), or any successor thereto; Upon determining Ge and Gt in subsection (iii) above, Seller shall then calculate for and provide the quantity of Free Allowances attributed to electric energy generated by the Generating Facility and delivered to Buyer for the applicable time-period (FAd) using the formula set forth in subsection (ii) of this definition.

“GAAP” means generally accepted accounting principles for financial reporting in the United States, consistently applied. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 11

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Gains” means, with respect to any Party, an amount equal to the present value of the economic benefit to it, if any (exclusive of Costs), as of the Early Termination Date resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the gain of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remaining Term and shall include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the gain of economic benefits, then the NonDefaulting Party may use information available to it internally. “Generating Facility” means the Generating Unit(s) comprising Seller’s power plant, as more particularly described in Section 1.02 and Exhibit B, including all other materials, equipment, systems, structures, features and improvements necessary for these Generating Units to produce electric energy and thermal energy, excluding the Site, land rights and interests in land. “Generating Unit” means one or more generating equipment combinations typically consisting of prime mover(s), electric generator(s), electric transformer(s), steam generator(s) and air emission control devices. The references to the term Generating Unit shall be applicable only to Generating Unit #1 and Generating Unit #3 throughout the Term. “Generating Unit #1” means the Generating Unit described in Section 1(a) of Exhibit B of this Agreement. “Generating Unit #3” means the Generating Unit described in Section 1(b) of Exhibit B of this Agreement. “Generation Operations Center” means the location of Buyer’s real-time operations personnel. “Generator Operator” means the Person that Operates the Generating Facility and performs the functions of supplying electric energy and interconnected operations services within the meaning of the NERC Reliability Standards. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 12

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Generator Operator Obligations” means the obligations of a Generator Operator as set forth in all applicable NERC Reliability Standards. “Generator Owner” means the Person that owns the Generating Facility and has registered with the NERC as the Person responsible for complying with all NERC Reliability Standards applicable to the owner of the Generating Facility. “Generator Owner Obligations” means the obligations of a Generator Owner as set forth in all applicable NERC Reliability Standards. “GHG Allowance Price” has the meaning set forth in Section 2(a)(ii) of Exhibit S. “GHG Auction” means any auction or other sale-by-bid event applicable to California and by an authorized Governmental Authority (or any entity authorized by such Governmental Authority) for the sale of Allowances. “GHG Charges” has the meaning set forth in Section 1 of Exhibit S. “GHG Compliance Costs” means the cost of Allowances, as determined in accordance with Exhibit S. “GHG Floor Test” has the meaning set forth in Section 2(a) of Exhibit S. “Governmental Authority” means (a) any federal, state, local, municipal or other government, (b) any governmental, regulatory or administrative agency, commission, or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power, or (c) any court or governmental tribunal. “Governmental Charges” has the meaning as set forth in Section 8.02. “Green Attributes” means any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1 (3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. “Greenhouse Gas” or “GHG” means emissions released into the atmosphere of carbon dioxide (CO2), nitrous oxide (N2O) and methane (CH4), which are produced as the result of combustion or transport of fossil fuels. Other greenhouse gases may include hydrofluorocarbons (HFCs), perfluorocarbons (PFCs) and sulfur hexafluoride (SF6), which are generated in a variety of industrial processes. Greenhouse gases may be defined or expressed in terms of a MT of CO2equivalent, in order to allow comparison between the different effects of gases on the environment; provided, however, that the definition of the term “Greenhouse Gas”, as set forth in

1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program. The contents of this document are subject to restrictions on disclosure as set forth herein.

Exhibit A

Definitions

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

the immediately preceding sentence, shall be deemed revised to include any update or other change to such term by the CARB or any other Governmental Authority. “Heat Rate” means, for purposes of this Agreement, the value obtained, in BTU per kWh, when the fuel input, on a Higher Heating Value basis, in BTU is divided by generation, net of Station Use, in kWh. “Higher Heating Value” means the high or gross heat content of the fuel with the heat of vaporization included (the water vapor is assumed to be in a liquid state). “Host Site” means the site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Related Entities located at such site. “Hour-Ahead Scheduling Deadline” means 30 minutes before the deadline established by the CAISO for the submission of schedules for the applicable hour. “Hourly Credit Value” is determined, as applicable, in Section 3(b) of Exhibit D-1, Section 3(b) of Exhibit D-2 and Section 9(b)(i) of Exhibit E. “Hourly Debit Value” is determined in Section 9(b)(ii) of Exhibit E. “Hourly Location Adjustment”, or “LA”, has the meaning set forth in Section 1 of Exhibit S. “Hourly Power Output” means an hourly rate of electric energy delivery, in kWh per hour, that is equal to the Metered Energy for one hour, in kWh, divided by one hour. “IFM” (i.e., the Integrated Forward Market) has the meaning set forth in the CAISO Tariff. “IFM Load Uplift Obligation” means the obligation of a Scheduling Coordinator to pay its share of unrecovered IFM Bid Costs (as defined in the CAISO Tariff) paid to resources through Bid Cost Recovery (as defined in the CAISO Tariff). “IFRS” has the meaning set forth in Section 3.20(b)(iii). “Incipient Event of Default” has the meaning set forth in Section 9.05(a). “Interconnection Study” means a study prepared by or on behalf of the Transmission Provider or the CAISO to evaluate the impact of the interconnection of the Generating Facility to the Transmission Provider’s electric system or the applicable Control Area operator’s electric grid. “Interest Rate” means an annual rate equal to the rate published in The Wall Street Journal as the “Prime Rate” (or, if more than one rate is published, the arithmetic mean of such rates) as of the date payment is due plus two percentage points; provided, however, that in no event shall the Interest Rate exceed the maximum interest rate permitted by Applicable Laws. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 15

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Inter-SC Trade” means a trade between Scheduling Coordinators of electric energy, Ancillary Service (as defined in the CAISO Tariff), or IFM Load Uplift Obligation in accordance with the CAISO Tariff. “JAMS” means the Judicial Arbitration and Mediation Services, Inc. or any successor entity. “kW” means a kilowatt (1,000 watts) of electric capacity or power output. “kWh” means a kilowatt-hour (1,000 watt-hours) of electric energy. “LAR” means local area reliability, which is any program of localized resource adequacy requirements established for jurisdictional load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by another Local Regulatory Authority having jurisdiction over the load serving entity. LAR may also be known as local resource adequacy, local RAR, or local capacity requirement in other regulatory proceedings or legislative actions. “LAR Showings” means the LAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction over the load serving entity. “Lease” means one or more agreements whereby Seller leases the Site(s) described in Section 1.02 and Exhibit B from a third party, the term of which lease begins on or before the Term Start Date and extends at least through the Term End Date. “Lender” means any third-party institution or entity or successor in interest or assignees that either (i) purchases the Generating Facility and then leases it to Seller under a Sale-Leaseback Transaction, or (ii) provides development, bridge, construction, or permanent debt or tax equity financing or refinancing (including an Equity Investment) for the Generating Facility to Seller or credit support in connection with this Agreement. “LGIA” (i.e., Large Generator Interconnection Agreement or Standard Large Generator Interconnection Agreement) has the meaning set forth in the CAISO Tariff. “Limited TOD Energy”, or “LE”, has the meaning set forth in Section 3(e) of Exhibit D. “LMPQF” has the meaning set forth in Section 1 of Exhibit S. “LMPTrading Hub” has meaning set forth in Section 1 of Exhibit S. “Local Regulatory Authority” has the meaning set forth in the CAISO Tariff. “Locational Marginal Price” has the meaning set forth in the CAISO Tariff.

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 16

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Losses” means, with respect to any Party, an amount equal to the present value of the economic loss to it if any (exclusive of Costs), as of the Early Termination Date, resulting from the termination of this Agreement, expressed in dollars and determined in a commercially reasonable manner. Factors used in determining the loss of economic benefit to a Party may include: (a) Reference to information supplied by one or more third parties, which shall exclude Related Entities of the Non-Defaulting Party, including quotations (either firm or indicative) of relevant rates, prices, yields, yield curves, volatilities, spreads or other relevant market data in the relevant markets; (b) Comparable transactions; (c) Forward price curves based on economic analysis of the relevant markets; and (d) Settlement prices for comparable transaction at liquid trading hubs (e.g., NYMEX); All of which should be calculated for the remainder of the Term and must include the value of Related Products. Only if the Non-Defaulting Party is unable, after using commercially reasonable efforts, to obtain third party information to determine the loss of economic benefits, then the Non-Defaulting Party may use information available to it internally. “MAEm” has the meaning set forth in Section 3(a) of Exhibit I. “MAE Failure” has the meaning set forth in Section 3(b) of Exhibit I. “Maintenance Credit Value”, or “MCV”, is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a Maintenance Outage or a Major Overhaul which has been properly scheduled in accordance with Exhibit E. “Maintenance Debit Value” is a value indicating how much allowance is used when Seller requests credit for a Maintenance Outage or a Major Overhaul in accordance with Exhibit E. “Maintenance Outage” means a time period during which Seller plans to reduce the Power Output of the Power Product, in full or in part, in order to facilitate maintenance work on the Generating Facility, other than a Major Overhaul. “Major Overhaul” means a time period during which Seller plans to remove the Generating Facility from Operation in order to dismantle the Generating Facility’s equipment for inspections, repairs or replacement, with the goal that such equipment will be reassembled and made available for Operation. “Major Overhaul Allowance” is a value indicating a Term-Year maximum allowance with which Seller can request credit for a Major Overhaul in accordance with Exhibit E. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 17

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Market Disruption Event” means, with respect to any MHR Source, any of the following events: (i) the permanent discontinuation or material suspension of trading in the exchange or in the market specified for determining a Market Heat Rate; (ii) the temporary or permanent discontinuance or unavailability of the MHR Source; or (iii) the temporary or permanent closing of any exchange specified for determining a Market Heat Rate. For purposes of this definition, “temporary” means five (5) or more continuous Trading Days. “Market Heat Rate” means the 12-month forward market heat rate, calculated for each calendar pricing month utilizing the methodology set forth in Commission Decision 07-09-040 and Commission Resolution E-4246 for SP15 Existing Zone Generation Trading Hub (formerly known as SP15), or its successor. Unless otherwise agreed to by the Parties, this definition of Market Heat Rate will not be updated by any subsequent decision, ruling or order by the CPUC. “Maximum Allowed Capacity”, or “MAC”, is determined in Section 3(d) of Exhibit D. “Maximum Firm Capacity Payment”, or “MFCP”, means the maximum payment that Seller can earn during a year for the delivery of Firm Contract Capacity that is calculated in accordance with the procedure set forth in Section 3(h) of Exhibit D. “Mediator” has the meaning set forth in Section 10.02. “Metered Amounts” means the quantity of electric energy, expressed in kWh, as recorded by (i) the CAISO-Approved Meter(s), which quantity may include compensation factors introduced by the CAISO into the CAISO-Approved Meter(s), or (ii) Check Meter(s), as applicable. “Metered Energy” means the quantity of electric energy, expressed in kWh, as measured by (i) the CAISO-Approved Meter(s), which quantity will be adjusted so as not to include compensation factors, if any, introduced by the CAISO into the CAISO-Approved Meter(s) other than (x) electric energy consumed within the generator collection system as losses between the generator(s) and the high voltage side of the Generating Facility output transformer(s) and, (y) if applicable, the Generating Facility’s radial line losses, or (ii) Check Meters, as applicable, in each case for the specified Metering Interval. “Metering Interval” means the smallest measurement time period over which data are recorded by the CAISO-Approved Meters or Check Meters. “MHR Source” the relevant publications used to determine the Market Heat Rate. “Monthly Contract Payment” has the meaning set forth in Section 4.01. “Monthly Scheduling Fee” is described in Section 4(b) of Exhibit G. “MT” means metric ton(s). “MW” means a megawatt (1,000,000 watts) of electric capacity or power output. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 18

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“MWh” means a megawatt-hour (1,000,000 watt-hours) of electric energy or power output. “NERC” means the North American Electric Reliability Corporation, or any successor entity. “NERC Reliability Standards” means the most recent version of those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by the NERC and approved by the applicable regulatory authorities, which are available at http://www.nerc.com/files/Reliability_Standards_Complete_Set.pdf, or any successor thereto. “NERC Standards Non-Compliance Penalties” means any and all monetary fines, penalties, damages, interest or assessments by the NERC, the CAISO, the WECC, a Governmental Authority or any Person acting at the direction of a Governmental Authority arising from or relating to a failure to perform the obligations of Generator Operator or Generator Owner as set forth in the NERC Reliability Standards. “Net Contract Capacity”, or “NCC”, means the sum of Firm Contract Capacity and As-Available Contract Capacity, as set forth in Section 1.02(d), as may be adjusted in accordance with Section 3.07(c). Net Contract Capacity may not exceed PMax. “Net Qualifying Capacity” has the meaning set forth in the CAISO Tariff. “Non-Availability Charges” has the meaning set forth in the CAISO Tariff. “Non-Defaulting Party” has the meaning set forth in Section 6.02. “Notice” means notices, requests, statements or payments provided in accordance with Section 9.07 and Exhibit N. “OMAR” means the Operational Metering Analysis and Reporting System operated and maintained by the CAISO as the repository of settlement quality meter data, or any successor thereto. “Operate,” “Operating,” or “Operation” means to provide (or the provision of) all the operation, engineering, purchasing, repair, supervision, training, inspection, testing, protection, use management, improvement, replacement, refurbishment, retirement, and maintenance activities associated with operating the Generating Facility in order to produce the Power Product in accordance with Prudent Electrical Practices. “Outage” has the meaning set forth in the CAISO Tariff. “Outage Schedule” has the meaning set forth in Section 2(a) of Exhibit R.

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

Page 19

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Outage Schedule Submittal Requirements” describes the obligations of Seller to submit maintenance and planned outage schedules (as defined in the CAISO Tariff under WECC rules) to Buyer 24 months in advance, as set forth in Exhibit R. “Parallel Operation” means the Generating Facility’s electrical apparatus is connected to the Transmission Provider’s system and the circuit breaker at the point of common coupling is closed. The Generating Facility may be producing electric energy or consuming electric energy at such time. “Party” has the meaning set forth in the Preamble. “Peak Months” means June, July, August and September. “Penalized As-Available Contract Capacity” has the meaning set forth in Section 3(b)(ii) of Exhibit I. “Penalized Firm Contract Capacity” has the meaning set forth in Section 3(b)(i) of Exhibit I. “Performance Tolerance Band Lower Limit” is determined in Section 1 of Exhibit K. “Performance Tolerance Band Upper Limit” is determined in Section 1 of Exhibit K. “Permits” means all applications, approvals, authorizations, consents, filings, licenses, orders, permits or similar requirements imposed by any Governmental Authority, or the CAISO, in order to develop, construct, Operate, maintain, improve, refurbish or retire the Generating Facility or to Forecast or deliver the electric energy produced by the Generating Facility to Buyer. “Person” means an individual, partnership, corporation, business trust, limited liability company, limited liability partnership, joint stock company, trust, unincorporated association, joint venture or other entity or a Governmental Authority. “PGA” (i.e., Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Physical Trade” has the meaning set forth in the CAISO Tariff. “Physical Trade Settlement Amount” means the dollar amount calculated in accordance with Exhibit L. “PIRP” (i.e., Participating Intermittent Resource Program) means the CAISO’s intermittent resource program initially established pursuant to Amendment No. 42 of the CAISO Tariff in Docket No. ER02-922-000, or any successor program that Buyer determines accomplishes a similar purpose. “PMax” has the meaning set forth in the CAISO Tariff.

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“PNode” has the meaning set forth in the CAISO Tariff. “Power Output” means the average rate of electric energy delivery during one Metering Interval, converted to an hourly rate of electric energy delivery, in kWh per hour, that is equal to the product of Metered Energy for one Metering Interval, in kWh per Metering Interval, times the number of Metering Intervals in a one-hour period. “Power Product” means (a) the Net Contract Capacity and (b) all electric energy produced by the Generating Facility, net of all Station Use and any and all of the Site Host Load. “PPT” means Pacific Daylight time when California observes Daylight Savings Time and Pacific Standard Time otherwise. “Primary Fuel” means the fuel or combination of fuels that are provided for in the Permits applicable to the Generating Facility. “Product” means the Power Product and the Related Products. “Project” means the Generating Facility. “Prudent Electrical Practices” means those practices, methods and acts that would be implemented and followed by prudent operators of electric generating facilities in the Western United States, similar to the Generating Facility, during the relevant time period, which practices, methods and acts, in the exercise of prudent and responsible professional judgment in the light of the facts known at the time a decision was made, could reasonably have been expected to accomplish the desired result consistent with good business practices, reliability and safety. Prudent Electrical Practices includes, at a minimum, those professionally responsible practices, methods and acts described in the preceding sentence that comply with the manufacturer’s warranties, restrictions in this Agreement, and the requirement of Governmental Authorities, WECC standards, the CAISO and Applicable Laws. Prudent Electrical Practices shall include taking reasonable steps to ensure that: (a) Equipment, materials, resources and supplies, including spare parts inventories, are available to meet the Generating Facility’s needs; (b) Sufficient operating personnel are available at all times and are adequately experienced, trained and licensed as necessary to Operate the Generating Facility properly and efficiently, and are capable of responding to reasonably foreseeable emergency conditions at the Generating Facility and Emergencies whether caused by events on or off the Site; (c) Preventative, routine, and non-routine maintenance and repairs are performed on a basis that ensures reliable, long term and safe operation of the Generating Facility, The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Southern California Edison

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

and are performed by knowledgeable, trained and experienced personnel utilizing proper equipment and tools; (d) Appropriate monitoring and testing are performed to ensure equipment is functioning as designed; (e) Equipment is not operated in a reckless manner, in violation of manufacturer’s guidelines or in a manner unsafe to workers, the general public or the Transmission Provider’s electric system, or contrary to environmental laws, permits or regulations or without regard to defined limitations, such as flood conditions, safety inspection requirements, operating voltage, current, volt ampere reactive (VAR) loading, frequency, rotational speed, polarity, synchronization, and control system limits; and (f) Equipment and components designed and manufactured to meet or exceed the standard of durability that is generally used for electric energy generation operations in the Western United States and will function properly over the full range of ambient temperature and weather conditions reasonably expected to occur at the Site and under both normal and emergency conditions. “PTSAi” has the meaning set forth in Section 2 of Exhibit L. “PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95-617, as amended from time to time. “QF PGA” (i.e., Qualifying Facility Participating Generator Agreement) has the meaning set forth in the CAISO Tariff. “Qualifying Cogeneration Facility” means an electric energy generating facility that: (a)

Complies with the “qualifying cogeneration facility” definition and other requirements (including the requirements set forth in 18 CFR Part 292, Section 292.205) established by PURPA and any FERC rules as amended from time to time implementing PURPA, as set forth in 18 CFR Part 292, Section 292.203 et seq.; and

(b)

Has filed with the FERC (i) an application for FERC certification, pursuant to 18 CFR Part 292, Section 292.207(b)(1), which the FERC has granted, or (ii) a notice of selfcertification pursuant to 18 CFR Part 292, Section 292.207(a).

“RAR” means the resource adequacy requirements established for load serving entities by the CPUC pursuant to the Resource Adequacy Rulings, or by a Local Regulatory Authority or other Governmental Authority having jurisdiction. “RAR Showings” means the RAR compliance showings (or similar or successor showings) a load serving entity is required to make to the CPUC (or, to the extent authorized by the CPUC, to The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

the CAISO), pursuant to the Resource Adequacy Rulings, or to a Local Regulatory Authority having jurisdiction. “Real-Time Forced Outage” means a Forced Outage which occurs only after 5:00 p.m. PPT on the day before the Trading Day. “Real-Time Market” has the meaning set forth in the CAISO Tariff. “Real-Time Price” means the Real-Time Market price for Uninstructed Imbalance Energy (as defined in the CAISO Tariff) or any successor price for short-term imbalance energy, as such price or successor price is defined in the CAISO Tariff, that would apply to the Generating Facility, which values are, as of the Effective Date, posted by the CAISO on its website. The values used in this Agreement will be those appearing on the CAISO website on the eighth Business Day of the calendar month following the month for which such prices are being applied. “Reference Market-Maker” means a leading dealer in the electric energy market that is not an Related Entity of either Party (or of a Trade Organization) and that is selected by a Party in good faith among dealers of the highest credit standing which satisfy all the criteria that such Party applies generally at the time in deciding whether to offer or to make an extension of credit. Such dealer may be represented by a broker. “Related Entity” means, with respect to a party, any Person that, directly or indirectly, through one or more intermediaries, controls, or is controlled by, or is under common control with such party. For purposes of this Agreement, “control” means the direct or indirect ownership of 50% or more of the outstanding capital stock or other equity interests having ordinary voting power. “Related Products” means (i) with respect to Resource Adequacy Benefits (a) that portion of the Resource Adequacy Benefits that are associated with the Firm Contract Capacity, and (b) to the extent that there are Resource Adequacy Benefits associated with the generating capacity of the Generating Facility other than the Firm Contract Capacity, that portion of the Resource Adequacy Benefits that are not associated with the Firm Contract Capacity and that are in excess of those Resource Adequacy Benefits used by Seller or by a Site Host, both in connection with the Host Site, to meet a known and established resource adequacy obligation under any Resource Adequacy Ruling at the point in time when the Resource Adequacy Benefits are to be used, and (ii) any Green Attributes, Capacity Attributes and all other attributes associated with the electric energy or capacity of the Generating Facility (but not including any Financial Incentives) that are in excess of those Green Attributes, Capacity Attributes or other attributes used, or retained for future use, by Seller or a Site Host, both in connection with the Host Site, to meet a known and established, at the point in time when the relevant attribute(s) are to be used or retained, obligation under Applicable Law. “Renewable Energy Credit” has the meaning set forth in Public Utilities Code Section 399.12(g), as may be amended from time to time or as further defined or supplemented by Applicable Law. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Resource Adequacy Benefits” means the rights and privileges attached to the Generating Facility that satisfy any Person’s resource adequacy obligations, as those obligations are set forth in any Resource Adequacy Rulings and shall include any local, zonal or otherwise locational attributes associated with the Generating Facility. “Resource Adequacy Resource” has the meaning set forth in the CAISO Tariff. “Resource Adequacy Rulings” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 0606-024, 06-07-031 and any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or promulgated by any applicable Governmental Authority, as such CPUC decisions, rulings, laws, rules or regulations may be amended or modified from time to time during the Term. “RFO Agreement” means the Power Purchase and Sale Agreement between the Parties, dated July 2, 2012, as may be amended from time to time. “RPS Program” means the State of California Renewable Portfolio Standard Program, as codified at California Public Utilities Code Section 399.11, et seq. “Sale-Leaseback Transaction” means a transaction in which Seller (i) sells the Generating Facility to a Lender providing tax equity financing to Seller and (ii) leases the Generating Facility from Lender under an agreement authorizing Seller to act in all matters relating to the control and Operation of the Site and the Generating Facility for the Term, subject to Lender’s right to terminate the lease in the event of a default by Seller as set forth in the agreement between Seller and Lender. “Schedule” means the action of the Scheduling Coordinator, or its designated representatives, of notifying, requesting, and confirming to the CAISO, the CAISO-Approved Quantity of electric energy. “Scheduled Amount” means the Day-Ahead Schedule comprised of the quantity (in MWh) of electric energy expected to be produced by the Generating Facility that is scheduled from Seller or Seller’s Scheduling Coordinator to Buyer in a Physical Trade in the IFM. “Scheduled Power Offline” is described in Section 3(b)(v) of Exhibit E. “Scheduling Coordinator” means a Person certified by the CAISO for the purposes of undertaking the functions specified in Exhibit G. “Scheduling Fee” means the Monthly Scheduling Fee and the SC Set-Up Fee. “SC Replacement Date” has the meaning set forth in Section 7(b) of Exhibit G. “SC Set-Up Fee” is described in Section 4(a) of Exhibit G. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“SC Trade Settlement Amount” means the amount(s) determined in accordance with Exhibit M. “SC Trade Tolerance Band” means the greater of (a) three percent of the Scheduled Amount or (b) one MW. “SDD Administrative Charge” has the meaning set forth in Section 2 of Exhibit K. “SDD Adjustment” means the adjustment, if any, to the Monthly Contract Payment, as determined in accordance with Exhibit K. “SDD Energy Adjustment” has the meaning set forth in Section 1 of Exhibit K. “SEC” means the United States Securities and Exchange Commission, or any successor entity. “Self-Schedule” has the meaning set forth in the CAISO Tariff. “Seller” has the meaning set forth in the Preamble. “Seller’s Day-Ahead Forecast” means the most recently updated Forecast submitted by 5:00 p.m. PPT on the day before the Trading Day. “Seller’s Energy Forecast” means Seller’s most recently updated Forecast submitted in accordance with Exhibit I. “Seller’s Final Energy Forecast” means Seller’s Energy Forecast as may be updated for Forced Outages that occur after the Hour-Ahead Scheduling Deadline, but not for Ambient Outages. “Settlement Agreement” has the meaning set forth in Recital C. “Settlement Effective Date” has the meaning set forth in Recital D. “Settlement Interval” has meaning set forth in the CAISO Tariff. “Settling Parties” has the meaning set forth in Recital B. “SGIA” (i.e., Small Generator Interconnection Agreement) means the form of Interconnection Request (as defined in the CAISO Tariff) pertaining to a Small Generating Facility (as defined in the CAISO Tariff), which is attached to the CAISO Tariff as Appendix T. “Simple Interest Payment” means a dollar amount calculated by multiplying the: (a) Dollar amount on which the Simple Interest Payment is based; by (b) Federal Funds Effective Rate or Interest Rate as applicable; by (c) The result of dividing the number of days in the calculation period by 360. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Site” means the real property on which the Generating Facility is located, as further described in Section 1.02(b) and Exhibit B. “Site Control” means that Seller (a) owns the Site, (b) is the lessee of the Site under a Lease, (c) is the holder of a right-of-way grant or similar instrument with respect to the Site, or (d) is managing partner or other Person authorized to act in all matters relating to the control and Operation of the Site and Generating Facility. “Site Host” means the Person or Persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating Facility. “Site Host Load” means the electric energy and capacity produced by or associated with the Generating Facility that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b). “SLIC” means Scheduling and Logging system for the CAISO. “Station Use” means the electric energy produced by the Generating Facility that is (a) used within the Generating Facility to power the lights, motors, control systems and other electrical loads that are necessary for Operation, and (b) consumed within the Generating Facility’s electric energy distribution system as losses needed to deliver electric energy to the Site Host Load, and (c) consumed within the generator collection system as losses between the generator(s) and the high voltage side of the Generating Facility output transformer(s). “Successor” has the meaning set forth in Section 3.20(b)(iii). “Supply Plan” has the meaning set forth in the CAISO Tariff. “System Emergency” has the meaning set forth in the CAISO Tariff. “Tariff Rule 21” means the interconnection standards of the Transmission Provider for distributed generation adopted by the CPUC in Decisions 00-11-001 and 00-12-037, as modified by the CPUC. “Telemetry System” means a system of electronic components that interconnects the CAISO and the Generating Facility in accordance with the CAISO’s applicable requirements as set forth in Section 3.09. “Term” has the meaning set forth in Section 1.01. “Term End Date” has the meaning set forth in Section 1.01. “Termination Payment” has the meaning set forth in Section 6.03. “Term Start Date” has the meaning set forth in Section 1.01. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Term Year” means a 12-month period beginning on the first day of the Term and each successive 12-month period thereafter. “TOD Period” means the time of delivery period used to calculate the Monthly Contract Payment set forth in Section 4 of Exhibit D. “TOD Period Capacity Payment” means the monthly payment to be calculated and made by Buyer to Seller for Power Product capacity during each TOD Period for the month for which a calculation is being performed, as set forth in Section 3(a) of Exhibit D, in dollars. “TOD Period Energy Payment” means the monthly payment to be calculated and made by Buyer to Seller for the Metered Energy during each TOD Period for the month for which a calculation is being performed, as set forth in Section 2(a) of Exhibit D, in dollars. “TOD Period Energy Price” means the price used to calculate the TOD Period Energy Payment, as set forth in Exhibit S and referenced in Section 2(b) of Exhibit D, in dollars per kWh. “TOU” has the meaning set forth in Section 1 of Exhibit S. “Trade Organizations” means the California Cogeneration Council, the Cogeneration Association of California, the Energy Producers and Users Coalition, and the Independent Energy Producers Association. “Trading Day” means the day in which Day-Ahead trading occurs in accordance with the WECC Preschedule Calendar (as found on the WECC’s website). “Transmission Curtailment Credit Value” or “TCV” is the adder applied to the Earned Capacity Hours to account for the time during which Seller is not able to meet the Firm Contract Capacity obligation due to a curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, as determined in accordance with Section 3 of Exhibit D-2. “Transmission Provider” means any Person responsible for the interconnection of the Generating Facility with the interconnecting utility’s electrical system or the CAISO Controlled Grid or transmitting the Metered Energy on behalf of Seller from the Generating Facility to the Delivery Point. “Transition EEI Agreement” means that certain Edison Electric Institute Master Power Purchase & Sale Agreement, together with the Cover Sheet, any amendments and annexes thereto (including the Collateral Annex and Paragraph 10 thereto) between Buyer and Seller, dated October 15, 2012. “Transition RA Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (RA Capacity), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

Definitions

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

“Transition Tolling Confirmation” means that certain Master Power Purchase and Sale Confirmation Letter (Energy Only UC Toll (Kern Pipeline – financially settled gas)), dated October 15, 2012, between the Parties and governed by the Transition EEI Agreement. “Uninstructed Deviation GMC Rate” means the administrative grid management charge applied by the CAISO to Uninstructed Deviations (as defined in the CAISO Tariff) using the absolute value for the Uninstructed Deviations by Settlement Interval. “Uninstructed Deviation Penalty” means the penalty set forth in the CAISO Tariff. “Useful Thermal Energy Output” has the meaning set forth in 18 CFR §292.202(h) and modified by the Energy Policy Act of 2005, or any successor thereto. “VOM” has the meaning set forth in Section 1 of Exhibit S. “Web Client” has the meaning set forth in Section 2(a) of Exhibit R. “Web Scheduler” has the meaning set forth in Section 2 of Exhibit E. “WECC” means the Western Electricity Coordinating Council, the regional reliability council for the western United States, northwestern Mexico, and southwestern Canada, or any successor entity. “WREGIS” means the Western Renewable Energy Generation Information System, or any successor thereto. *** End of Exhibit A ***

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit A

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT B Generating Facility and Site Description 1.

Generating Facility Description. (a)

Generating Unit Features. Each Generating Unit has:

(b)

(i)

One General Electric Frame 7 gas turbine, with a nominal electric capacity rating of 76.56 MW;

(ii)

A bypass exhaust stack for simple cycle operation; and

(iii)

A heat recovery steam generator (HRSG) that is used to turn produced water from the oil field into steam for use in an enhanced oil recovery system.

Interconnection Utility System The Generating Facility has been operating in parallel with SCE’s Transmission System since 1988. The Generating Facility consists of a SCE designed and built 220kV switchyard with connections to the four generating units and to a SCE owned transmission line which transmits power to the SCE owned Magunden substation.

(d)

{SCE Comment: Provide description of the Generating Facility equipment, systems, electric metering and the Seller’s measurement of theMeasurement of Useful Thermal Energy Output, control systems and features, including a site plan drawing and a oneline diagram, and the generator nameplate(s).}

Seller sells useful thermal energy output (steam) to Chevron U.S.A. Inc. for use in its enhanced oil recovery system under a long-term sales agreement. The Generating Facility supplies thermal energy in the form of saturated steam comprised of approximately 75% steam and 25% water. Useful thermal energy is calculated using the measured mass flow through the HRSG, measured feedwater temperature, measured steam pressure, measured steam quality, and the ASME steam tables to calculate BTU content of the steam. (e)

Control Systems The balance of plant control system is an Emerson Ovation Distributed Control System (DCS) utilizing redundant controllers. The redundant controllers provide greater reliability by allowing continued plant operation with the loss of a control

Exhibit B

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Page 1

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

processor. Multiple operator interfaces allow the plant operator to maintain control of the turbine with the loss of an operator interface. Non-critical equipment may be controlled by individual Programmable Logic Controller’s (PLC) or vendor supplied controllers that interface to the balance of plant DCS. (f)

Generating Unit #1 (i)

Name: Sycamore Cogeneration Company Unit #1

(ii)

Location: Bakersfield, California

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): As of the Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the Term Start Date, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: Unknown MW. As soon as possible Seller, but no later than 30 days prior to the Term Start Date, shall provide notice to Buyer of Unit NQC (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South

Exhibit B

(ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to

The contents of this document are subject to restrictions on disclosure as set forth herein. Generating Facility and Site Description

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

maintain visibility and control of the turbine with the loss of an operator interface. (g)

Generating Unit #3 (i)

Name: Sycamore Cogeneration Company Unit #3

(ii)

Location: Bakersfield, California

(iii)

CAISO Resource ID (as defined in the CAISO Tariff): As of the Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the Term Start Date, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(iv)

Unit NQC (as defined in the CAISO Tariff) as of the Effective Date: Unknown MW. As soon as possible, but no later than 30 days prior to the Term Start Date, Seller shall provide notice to Buyer of Unit NQC (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

(v)

Resource Type: Other- Frame7E

(vi)

Resource Category (1, 2, 3 or 4): 4

(vii)

Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation

(viii) Path 26 (North, South or None): South

Exhibit B

(ix)

Local Capacity Area (if any, as of Effective Date): Big Creek - Ventura

(x)

Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

(xi)

The gas turbine is controlled by a GE Mark V control system. The Mark V is a triple redundant control system powered by the 125VDC unit battery and uses triple redundant critical field sensors. Triple redundancy provides greater reliability by allowing the gas turbine to continue operation with loss of a control processor or a critical field sensor. The unit can be operated and monitored at the unit or in the plant control room using multiple operator interfaces. This allows the plant operator to maintain visibility and control of the turbine with the loss of an operator interface.

The contents of this document are subject to restrictions on disclosure as set forth herein. Generating Facility and Site Description

Page 3

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Exhibit B

The contents of this document are subject to restrictions on disclosure as set forth herein. Generating Facility and Site Description

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(h)

Exhibit B

Single-line Diagram

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(i)

Exhibit B

Site Plan Drawing

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

2.

Site Description. {SCE Comment: Provide a legal description of the Site, including the Site map.}

(a) Sycamore Cogeneration Company Plant Site (i)

PARCEL 1. That portion of that certain patented placer mining claim known as Amazon Placer Mining Claim described in the patent as the Southwest Quarter at the Southeast Quarter of Section 30, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area, County of Kern, State of California, according to the official plat thereof, which is included within the South 10 acres of the Southwest Quarter of the South east Quarter of said Section. Except any veins or lodes of quartz or other rock in place bearing gold, silver, cinnabar, lead, tin, copper or other valuable deposits within the land above described which may have been discovered or known to exist on or prior to August 23, 1915.

(ii)

PARCEL 2. The Northwest Quarter of the Northeast Quarter of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof.

(iii)

PARCEL 3. The North Half of Lot 1 of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof.

(b)

Site Control Seller has legal control of the Site under a 1987 Ground Lease from Chevron U.S.A. (CUSA), as amended in 1987 and 2008. Seller also has easement agreements with CUSA providing for ingress and egress to the Site and all other necessary rights-of-way for operation of Seller.

(c)

Exhibit B

Site Map

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Exhibit B

The contents of this document are subject to restrictions on disclosure as set forth herein. Generating Facility and Site Description

Page 8

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Exhibit B

The contents of this document are subject to restrictions on disclosure as set forth herein. Generating Facility and Site Description

Page 9

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

*** End of Exhibit B ***

Exhibit B

The contents of this document are subject to restrictions on disclosure as set forth herein. Generating Facility and Site Description

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT C [Intentionally omitted.] *** End of Exhibit C ***

Exhibit C

The contents of this document are subject to restrictions on disclosure as set forth herein. [Intentionally omitted.]

Page 1

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT D Monthly Contract Payment Calculation

1.

Introduction. Each Monthly Contract Payment is calculated on a calendar month basis as follows: MONTHLY CONTRACT PAYMENT, in dollars = TOD Period Energy Payment 1st TOD Period TOD Period Energy Payment 2nd TOD Period TOD Period Energy Payment 3rd TOD Period TOD Period Energy Payment 4th TOD Period TOD Period Capacity Payment 1st TOD Period TOD Period Capacity Payment 2nd TOD Period TOD Period Capacity Payment 3rd TOD Period TOD Period Capacity Payment 4th TOD Period

+ + + + + + +

All TOD Period Energy Payments shall be calculated as set forth in Section 2 of this Exhibit D. All TOD Period Capacity Payments shall be calculated as set forth in Section 3 of this Exhibit D. The “1st TOD Period,” “2nd TOD Period,” “3rd TOD Period” and “4th TOD Period” subscripts refer to the four TOD Periods that apply for the calculation month, as set forth in Section 4 of this Exhibit D. 2.

TOD Period Energy Payment Calculation. (a)

Each monthly TOD Period Energy Payment is calculated as follows: LastHour

TOD PERIOD ENERGY PAYMENT, in dollars = LA x MA]



FirstHour

[(EP-LA) x APE +

Where: EP

= TOD Period Energy Price, stated in Section 2(b) of this Exhibit D, in dollars per kWh.

APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D.

Exhibit D

The contents of this document are subject to restrictions on disclosure as set forth herein. Monthly Contract Payment Calculation

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. APE = The sum of the Allowed Payment Energy from the Generating Facility for each hour of the TOD Period, in kWh, as determined in accordance with Section 2(c) of this Exhibit D. LA = Hourly Location Adjustment price, as set forth in Section 1 of Exhibit S. MA = Metered Amounts for each hour of the applicable TOD Period, in kWh. Metered Amounts for any hour is equal to the sum of Metered Amounts for all Metering Intervals in that hour. First Hour = First hour of the applicable TOD Period. Last Hour = Last hour of the applicable TOD Period. Once 120% of the Expected Term Year Net Energy Production is achieved, no further electric energy payments will be calculated for the remaining TOD Periods within any remaining months of the current Term Year. (b)

Factor “EP” in Section 2(a) of this Exhibit D. The TOD Period Energy Price, in dollars per kWh, for any TOD Period shall be calculated pursuant to and as determined by the methodology set forth in Exhibit S.

(c)

Factor “APE” in Section 2(a) of this Exhibit D. The Allowed Payment Energy for each hour of each TOD Period of any month is calculated as follows: APE = The sum of the Metered Energy when Buyer is Scheduling Coordinator or Scheduled Amounts when Buyer is not Scheduling Coordinator from the Generating Facility for each hour of the TOD Period, in kWh.

3.

TOD Period Capacity Payment Calculation. (a)

Each monthly TOD Period Capacity Payment is calculated on a calendar month basis as follows: TOD PERIOD CAPACITY PAYMENT in dollars = (ACP + FCP) x CAF Where:

Exhibit D

ACP =

As-Available Capacity Payment for the TOD Period, as determined in accordance with Section 3(b) of this Exhibit D, in dollars per year.

FCP =

Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(g) of this Exhibit D, in dollars per year.

CAF =

The CPUC approved Capacity Payment Allocation Factor for the TOD Period in the year, based upon the formula adopted by the CPUC in D.01-03-067:

The contents of this document are subject to restrictions on disclosure as set forth herein. Monthly Contract Payment Calculation

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company Season Summer Winter

(b)

Capacity Payment Allocation Factors TOD Period On-Peak Period Mid-Peak Off-Peak Mid-Peak Off-Peak Super-Off-Peak

Factor 0.1792 0.0310 0.0006 0.0178 0.0011 0.0007

Factor “ACP” in Section 3(a) of this Exhibit D. The As-Available Capacity Payment shall be calculated pursuant to the following formula: AS-AVAILABLE CAPACITY PAYMENT, in dollars = AAC x AACP Where: AAC = As-Available Capacity for the TOD Period, as determined in accordance with Section 3(c) of this Exhibit D, in kWh per hour. AACP= The As-Available Capacity Price adopted by the CPUC in the Decision for the applicable year as set forth in the following table: Year 2011 2012 2013 2014 2015

(c)

As-Available Capacity Price Price $/kW-yr 41.22 43.09 45.00 46.97 48.98

Factor “AAC” in Section 3(b) of this Exhibit D. The As-Available Capacity for each TOD Period of each month is calculated as follows: AS-AVAILABLE CAPACITY, in kWh per hour = MAC – FCC (but not less than zero) Where: MAC = The Maximum Allowed Capacity for the TOD Period as determined in Section 3(d) in this Exhibit D, in kWh per hour. FCC = The Firm Contract Capacity for all TOD Periods during a month.

(d)

Factor “MAC” in Section 3(c) of this Exhibit D. The Maximum Allowed Capacity for each monthly TOD Period is calculated as follows: MAXIMUM ALLOWED CAPACITY, in kWh per hour

Exhibit D

= LE / PH

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Where: LE

= The sum of the Limited TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(e) of this Exhibit D, in kWh.

PH = The total number of hours in the TOD Period (period hours). (e)

Factor “LE” in Section 3(d) of this Exhibit D. The Limited TOD Energy for each TOD Period of any month is calculated as follows: LastHour

LIMITED TOD ENERGY, in kWh =



FirstHour

(E)Hour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour, in kWh; and (ii) Allowed Hourly Energy, as determined in Section 3(f) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (f)

Factor “E” in Section 3(e) of this Exhibit D. The Allowed Hourly Energy is calculated as follows: ALLOWED HOURLY ENERGY in kWh

= 1 hour x NCC

Where: NCC = The Net Contract Capacity, as set forth in Section 1.02(d), in kW. (g)

Factor “FCP” in Section 3(a) of this Exhibit D. Each monthly Firm Capacity Payment is calculated as follows: FIRM CAPACITY PAYMENT in dollars = MFCP x AF Where: MFCP = Maximum Firm Capacity Payment for the TOD Period, as determined in accordance with Section 3(h) of this Exhibit D, in dollars.

Exhibit D

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AF

= (i)

One (1), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is greater than or equal to 95%; or

(ii)

Zero (0), if the Availability Credit Factor, as calculated in Section 3(i) of this Exhibit D is less than 60%; or

(iii) If neither (i) nor (ii) are true, then AF is the Availability Penalty Factor, as calculated in Section 3(n) of this Exhibit D. (h)

Factor “MFCP” in Section 3(g) of this Exhibit D. The Maximum Firm Capacity Payment for each TOD Period of each month is calculated as follows: MAXIMUM FIRM CAPACITY PAYMENT, in dollars = FCC x CP Where: FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d), in kWh per hour. CP

(i)

= Firm Capacity Price, as set forth in Section 1.06(a), in $/kW-year.

Factor “ACF” in Section 3(g) of this Exhibit D. The Availability Credit Factor for each monthly TOD Period is calculated as follows: AVAILABILITY CREDIT FACTOR

= (ECH + CCH) / PH

Where: ECH = The total number of Earned Capacity Hours, determined in accordance with Section 3(j) of this Exhibit D. CCH = The total number of Capacity Credit Hours, determined in accordance with Section 3(m) of this Exhibit D. PH = The total number of hours in the TOD Period (period hours). (j)

Factor “ECH” in Section 3(i) of this Exhibit D. The Earned Capacity Hours for each monthly TOD Period is calculated as follows: EARNED CAPACITY HOURS

=

FE / FCC

Where: FE

Exhibit D

= The sum of the Firm TOD Energy from the Generating Facility for all hours of the TOD Period, as determined in Section 3(k) of this Exhibit D, in kWh.

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FCC = The Firm Contract Capacity for all TOD Periods during a month is the amount in Section 1.02(d) in kWh per hour. (k)

Factor “FE” in Section 3(j) of this Exhibit D. The Firm TOD Energy for each TOD Period of any month is calculated as follows: LastHour

FIRM TOD ENERGY in kWh



FirstHour

=

(E)Hour

Where: E

= The lesser of: (i) Metered Energy for the applicable hour in kWh; and (ii) Allowed Firm Energy, as determined in Section 3(l) of this Exhibit D, in kWh. First Hour

=

First hour of the applicable TOD Period.

Last Hour

=

Last hour of the applicable TOD Period.

Metered Energy for any hour is equal to the sum of Metered Energy for all Metering Intervals in that hour. (l)

Factor “E” in Section 3(k) of this Exhibit D. The Allowed Firm Energy is calculated as follows: ALLOWED FIRM ENERGY in kWh

= 1 hour x FCC

Where: FCC = The Firm Contract Capacity set forth in Section 1.02(d). (m)

Factor “CCH” in Section 3(i) of this Exhibit D. The total number of Capacity Credit Hours for each monthly TOD Period is determined as follows: CAPACITY CREDIT HOURS

= TCV + FCV + MCV

Where: TCV = The total Transmission Curtailment Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-2, when the Metered Energy was curtailed by either the CAISO or the Transmission Provider. FCV = The total Force Majeure Credit Value during the TOD Period, determined in accordance with Section 3 of Exhibit D-1, when the

Exhibit D

The contents of this document are subject to restrictions on disclosure as set forth herein. Monthly Contract Payment Calculation

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Metered Energy was curtailed by a Force Majeure event claimed by Buyer to the extent the Generating Facility is otherwise available. MCV = The total Maintenance Credit Value during the TOD Period, determined in accordance with Section 9 of Exhibit E. (n)

Factor “APF” in Section 3(g) of this Exhibit D. The Availability Penalty Factor for each monthly TOD Period is calculated as follows: AVAILABILITY PENALTY FACTOR = 1.0 – 2.0 x (CR – ACF) Where: APF = The greater of: (i) zero; and (ii) the result of the above equation for APF. CR = 95%, the minimum Capacity Performance Requirement. ACF = The Availability Credit Factor determined in accordance with Section 3(i) of this Exhibit D.

4.

Time of Delivery Periods. TOD Period On-Peak

Summer Jun 1st – Sep 30th Noon – 6:00 p.m.

Winter Oct 1st – May 31st Not Applicable.

8:00 a.m. – Noon

Applicable Days Weekdays except Holidays. Weekdays except Holidays.

Mid-Peak

8:00 a.m. - 9:00 p.m. 6:00 p.m. – 11:00 p.m.

Weekdays except Holidays. 6:00 a.m. – 8:00 a.m.

Weekdays except Holidays.

9:00 p.m. – Midnight

Weekdays except Holidays.

Midnight – Midnight

6:00 a.m. – Midnight

Weekends and Holidays.

Not Applicable.

Midnight – 6:00 a.m.

Weekdays, Weekends and Holidays.

11:00 p.m. – 8:00 a.m. Off-Peak

Super-Off-Peak

“Holiday”, as used in the above table, means New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, and Christmas Day. When a Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. *** End of Exhibit D ***

Exhibit D

The contents of this document are subject to restrictions on disclosure as set forth herein. Monthly Contract Payment Calculation

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EXHIBIT D-1 Force Majeure Credit Value 1.

Overview. This Exhibit D-1 describes the methodology for computing Force Majeure Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Force Majeure Credit Value. For every period of Force Majeure curtailment requested by Buyer, Buyer shall compute the Force Majeure Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-1, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the Force Majeure event and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of Benchmark Capacity minus Hourly Power Output or zero In case of division by zero, the value being calculated shall be zero.

Exhibit D-1

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Force Majeure Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Force Majeure Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. *** End of Exhibit D-1 ***

Exhibit D-1

The contents of this document are subject to restrictions on disclosure as set forth herein. Force Majeure Credit Value

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EXHIBIT D-2 Transmission Curtailment Credit Value 1.

Overview. This Exhibit D-2 describes the methodology for computing Transmission Curtailment Credit Value.

2.

Scheduling. Each Curtailment Period shall be scheduled to start and stop at the beginning of an hour. Also, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

3.

Calculation of Transmission Curtailment Credit Value. For every period of curtailment of Power Product requested by the Transmission Provider, the CAISO or otherwise, Buyer shall compute the Transmission Curtailment Credit Value following these steps: (a)

A Benchmark Capacity shall be determined for every Curtailment Period. For purposes of this Exhibit D-2, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, during the first 24hour period which precedes the curtailment notification and does not overlap another Curtailment Period, Maintenance Outage, or Major Overhaul. Notwithstanding this Section 3(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Curtailment Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during the Curtailment Period and that would have been able to return to service during the Curtailment Period but for the circumstances constituting the Curtailment Period.

(b)

For each hour in the Curtailment Period, an Hourly Credit Value shall be calculated using following formula: Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the greater of: Benchmark Capacity minus Hourly Power Output or zero In case of division by zero, the value being calculated shall be zero.

Exhibit D-2

The contents of this document are subject to restrictions on disclosure as set forth herein. Transmission Curtailment Credit Value

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(c)

For each hour in the Curtailment Period, the Hourly Credit Value shall be applied as Transmission Curtailment Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Curtailment Period have been applied.

(d)

After all the Hourly Credit Values have been applied, the final monthly Transmission Curtailment Credit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision. ______________________________________________________________________________ *** End of Exhibit D-2 ***

Exhibit D-2

The contents of this document are subject to restrictions on disclosure as set forth herein. Transmission Curtailment Credit Value

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT E Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits 1.

Overview. Seller shall follow the protocols established in this Exhibit E for the scheduling of Maintenance Outages and Major Overhauls, and for any subsequent notification that may be required to update a previously scheduled Maintenance Outage or Major Overhaul for which Seller wishes to obtain Maintenance Credit Value. This Exhibit E also describes the methodology for computing Maintenance Credit Value and Maintenance Debit Value.

2.

Notification. Seller shall direct all Maintenance Outage and Major Overhaul notifications to Buyer’s web-based outage scheduling system or an e-mail address designated by Buyer (the “Web Scheduler”) and to the Generation Operations Center, whose URL and telephone number(s) can be found in Exhibit N.

3.

Scheduling. (a)

Seller shall schedule all Maintenance Outages and Major Overhauls with Buyer in advance. Seller’s failure to schedule an unplanned outage in advance is not a default under this Agreement. The notice requirements for Maintenance Outages and Major Overhauls are as follows: Outage Duration Maintenance Outage, Less than 1 day Maintenance Outage, 1 day or more Major Overhaul

(b)

Exhibit E

Minimum Advance Notice 24 Hours 168 Hours 6 Months

Seller shall provide the following information when scheduling a Maintenance Outage or a Major Overhaul via the Web Scheduler: (i)

The identification number set forth on the cover page of this Agreement;

(ii)

Password (supplied by Buyer);

(iii)

Generating Unit Number*;

(iv)

Capacity Credit Period, including: (1)

The date and time when Seller expects the Capacity Credit Period to begin, and

(2)

The date and time when Seller expects the Capacity Credit Period to end.

The contents of this document are subject to restrictions on disclosure as set forth herein. Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

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(v)

“Scheduled Power Offline”**, in kW, is the Hourly Power Output that is expected to be offline during each hour of the outage period, as such may be updated as set forth in this Exhibit E; and

(vi)

Reason for the requested Maintenance Outage or Major Overhaul.

*Unit designation is applicable only when the contract calls for separate tracking of outage allowance for each Generating Unit. **If unit designation is applicable, Seller must provide the expected Scheduled Power Offline of the Generating Unit scheduled for maintenance; otherwise, Seller must provide the expected Scheduled Power Offline of the Generating Facility. 4.

Rescheduling. (a)

A Maintenance Outage and the associated Capacity Credit Period may be rescheduled if Seller’s request to reschedule is received by Buyer no later than 5:00 p.m. PPT on the day before the Maintenance Outage was previously scheduled to begin.

(b)

A Major Overhaul and the associated Capacity Credit Period may be rescheduled provided:

(c) 5.

(i)

The rescheduled Major Overhaul begins six months or more after the first outage notification date and time;

(ii)

The notification to reschedule is made at least one week before the Major Overhaul was previously scheduled to begin; and

(iii)

There is at least a one-month period between the notification to reschedule and the commencement of the rescheduled Major Overhaul.

Maintenance Outages and Major Overhauls may be rescheduled more than once.

Extension. (a)

Seller may extend a Maintenance Outage or a Major Overhaul and the associated Capacity Credit Period by notifying Buyer of the extension no later than 5:00 p.m. PPT on the day before the outage was previously scheduled to end. Seller’s failure to provide such notice, to the extent resulting from unexpected circumstances, is not a default under this Agreement.

(b)

Maintenance Outages and Major Overhauls and the associated Capacity Credit Periods may be extended more than once.

Exhibit E

The contents of this document are subject to restrictions on disclosure as set forth herein. Scheduling and Calculation of Maintenance Outage and Major Overhaul Credits

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(c)

For a Maintenance Outage and the associated Capacity Credit Period which is less than 24 hours in duration, the extension cannot result in a total outage duration greater than 23 hours.

6.

Cancellation. If Seller cancels a scheduled Maintenance Outage, Major Overhaul or the associated Capacity Credit Period, a cancellation notice must be received by Buyer no later than 5:00 p.m. PPT on the day before such Maintenance Outage or Major Overhaul was scheduled to begin.

7.

Updating Scheduled Power Offline.

8.

9.

(a)

If a change in the Hourly Power Output is anticipated or occurs during a Maintenance Outage or a Major Overhaul, the Scheduled Power Offline must be updated on a prospective basis as soon as possible via the Web Scheduler. Scheduled Power Offline cannot be updated once the Maintenance Outage or Major Overhaul is over.

(b)

Multiple updates to the Scheduled Power Offline can be submitted if necessary on a prospective basis.

(c)

If a Maintenance Outage or a Major Overhaul is completed ahead of schedule and Seller’s Hourly Power Output has returned to normal output levels earlier than expected, Seller shall advise Buyer of the situation by providing an update to the Scheduled Power Offline as described in Section 7(a) of this Exhibit E.

Restrictions. (a)

Seller shall make reasonable efforts not to schedule a Maintenance Outage or Major Overhaul during the Peak Months. Should an outage be required during the said period, Seller shall abide by the limit as set forth in Section 1.05(d) for minor maintenance work during peak months.

(b)

Each Capacity Credit Period must be scheduled to start and stop at the beginning of an hour. Also, when scheduling an outage, the notification time shall be rounded to the nearest hour. For example: 11:29 becomes 11:00 and 11:30 becomes 12:00.

(c)

Seller may not schedule a Maintenance Outage or a Major Overhaul that overlaps another Maintenance Outage, Major Overhaul, or Curtailment Period already scheduled on the Generating Facility. If unit designation is applicable in Section 3(b)(iii) of this Exhibit E, this restriction applies to the Generating Unit.

Maintenance Credit Calculation. For every properly scheduled Maintenance Outage and Major Overhaul, to the extent there is an associated Capacity Credit Period, Buyer shall

Exhibit E

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compute and apply the associated Maintenance Credit Value and the Maintenance Debit Value following these steps: (a)

A Benchmark Capacity shall be determined for every scheduled Maintenance Outage and Major Overhaul. For purposes of this Exhibit E, “Benchmark Capacity” is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, at or after the time of outage notification, and before the start of the outage. If the outage is rescheduled, the most recent notification time shall be used in defining Benchmark Capacity. If the outage is extended, or its Scheduled Power Offline is updated, the original notification time shall be used in defining Benchmark Capacity, unless the outage has been rescheduled before the extension, in which case the most recent rescheduling notification time shall be used in defining Benchmark Capacity. In the special case of a less-than-one-day Maintenance Outage that directly follows another less-than-one-day Maintenance Outage, Benchmark Capacity of the outage that follows is defined as the highest Hourly Power Output, not to exceed Firm Contract Capacity, between these two outage time periods. In the event of back-to-back, less-than-one-day Maintenance Outages, Benchmark Capacity for the second outage shall be zero. Notwithstanding this Section 9(a), upon Seller’s request, if and to the extent Seller is able to demonstrate to Buyer’s reasonable satisfaction that some or all of the Firm Contract Capacity of the Generating Facility available before the Benchmark Capacity was established was not available during the period when the Benchmark Capacity was established but became available during the Capacity Credit Period, the Benchmark Capacity will be adjusted to include such portion of the Firm Contract Capacity that became available during such Capacity Credit Period.

(b)

For each hour in the Capacity Credit Period of the Maintenance Outage or the Major Overhaul, an Hourly Credit Value and Hourly Debit Value shall be calculated using following formulas: (i)

Hourly Credit Value = ( Delta / Firm Contract Capacity ) * 1 hour where Delta is the lesser of Benchmark Capacity minus Hourly Power Output, or Scheduled Power Offline. However, in all cases, Delta shall never be less than zero.

Exhibit E

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(ii)

Hourly Debit Value = (Scheduled Power Offline / Firm Contract Capacity) * 1 hour

(c)

For each hour in the Capacity Credit Period, the Hourly Credit Value shall be applied as Maintenance Credit Value, by TOD Period, to the Capacity Credit Hours in Section 3(m) of Exhibit D, until the Hourly Credit Values for all hours in the Capacity Credit Period have been applied, or until the condition described in Section 9(d) of this Exhibit E is met, whichever comes first.

(d)

Simultaneous to Section 9(c) of this Exhibit E, for each hour in the Capacity Credit Period, the Hourly Debit Value shall be accumulated as Maintenance Debit Value in a Term-Year-to-date account whose increasing total is to be compared to the appropriate limit set forth in Sections 1.05(a) or (b). Once the Term-Year-todate total reaches or exceeds the limit, no more Hourly Credit Values shall be applied.

(e)

After all the Hourly Credit Values have been applied and the Hourly Debit Values accounted for, the final monthly Maintenance Credit Value and the Term-Year-todate cumulative Maintenance Debit Value shall be rounded to the nearest whole number. However, all intermediate computations leading up to the final result shall be carried out with appropriate numeric precision.

The above description of the evaluation process assumes that the outage was properly scheduled with sufficient advance notice pursuant to this Exhibit E and was approved by Buyer (or the CAISO, if applicable). Any deviation from the proper scheduling protocol can result in reduced Maintenance Credit Value or increased Maintenance Debit Value. *** End of Exhibit E ***

Exhibit E

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EXHIBIT F [Intentionally omitted.] *** End of Exhibit F ***

Exhibit F

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EXHIBIT G Scheduling Coordinator Services This Exhibit G is only applicable when Buyer is Scheduling Coordinator. 1.

2.

Designation of Buyer as Scheduling Coordinator. (a)

At least 30 days before the Term Start Date, Seller shall take all actions and execute and deliver to Buyer and the CAISO all documents necessary to authorize or designate Buyer as Scheduling Coordinator with the CAISO effective as of the Term Start Date.

(b)

During the Term, unless Seller terminates Buyer as Scheduling Coordinator in accordance with Section 7 of this Exhibit G, Seller may not authorize or designate any other party to act as Scheduling Coordinator, nor shall Seller perform for its own benefit the duties of Scheduling Coordinator, and Seller may not revoke Buyer’s authorization to act as Scheduling Coordinator unless agreed to by Buyer.

(c)

Buyer shall submit bids and schedules to the CAISO in accordance with the CAISO Tariff and Seller’s QF PGA or PGA, as applicable.

(d)

Buyer shall submit all required notices and updates regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO in accordance with the CAISO procedures.

(e)

Seller is not entitled to any Monthly Capacity Payment until Buyer is fully authorized as Scheduling Coordinator for the Generating Facility; provided, however, that Buyer may not take, or not refrain from taking, any action if the result would be to delay such authorization.

Buyer’s Scheduling Responsibilities. Pursuant to the CAISO Tariff, Buyer shall be responsible for the following: (a)

Using the Forecast submitted by Seller to Buyer pursuant to Exhibit I, including updated Forecasts to the extent reasonably practicable, to forecast Seller’s expected generation using Buyer’s forecasting model (“Buyer Projected Energy Forecast”) in any given hour;

(b)

Adjusting Buyer Projected Energy Forecast for forecasted electric energy line losses in accordance with the amount of electric energy Seller is expected to deliver to the Delivery Point;

(c)

Submitting the adjusted Forecasts to the CAISO as Scheduling Coordinator Schedules (as defined in the CAISO Tariff); and

Exhibit G

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(d)

Receiving notification of the final schedules from the CAISO.

3.

Notices. As Scheduling Coordinator, Buyer shall submit all notices and updates required under the CAISO Tariff and Applicable Laws regarding each Generating Unit’s or the Generating Facility’s status, as applicable, to the CAISO, including all SLIC Outage requests, SLIC Forced Outages, CAISO Forced Outage Reports, or must offer waiver forms.

4.

Scheduling Fees. In accordance with Section 4.02, Buyer shall invoice to Seller and Seller shall pay to Buyer the following Scheduling Fees: (a)

SC Set-Up Fee. The SC Set-Up Fee is equal to the costs Buyer incurs as a result of the Generating Units or the Generating Facility registration, as applicable, as well as installation, configuration, and testing of all equipment and software necessary, in Buyer’s sole discretion, to Schedule the Generating Unit or the Generating Facility, as applicable, in accordance with the CAISO Tariff. Buyer’s invoice to Seller shall provide a detailed accounting of all costs and charges encompassed in the SC Set-Up Fee, including separate line items for registration charges, equipment costs, software costs, and labor costs (including hourly rate if applicable) itemized for registration, equipment installation, configuration, testing and software related charges. Buyer estimates that the SC Set-up Fee for this Agreement will equal $1,450.

(b)

Monthly Scheduling Fee. The Monthly Scheduling Fee will be as forth in the following table.

Net Contract Capacity (kW)

Monthly Scheduling Fee

Less than 10,000

$2,500

10,000 – 100,000

$5,000

Greater than 100,000

$7,500

5. CAISO Settlements. As Scheduling Coordinator, Buyer shall be responsible for all settlement functions with the CAISO related to the Generating Units or the Generating Facility, as applicable. Seller shall cooperate with Buyer in Buyer’s performance of any settlement functions, and Seller shall promptly deliver to Buyer, or provide Buyer access to, all Generating Unit or the Generating Facility, as applicable, data necessary for CAISO settlements and any correspondence or communications with CAISO related to the Generating Units or the Generating Facility, as applicable, including any invoices or settlement data, in the mutually agreed upon format reasonably requested by Buyer.

Exhibit G

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Buyer shall render a separate invoice to Seller for all CAISO Charges for which Seller is responsible under this Agreement (“CAISO Charges Invoice”) as described in Sections 1 through 4 of Exhibit J, in accordance with the applicable billing and payment methodologies utilized for the specific CAISO Charge as set forth in the CAISO Tariff. CAISO Charges Invoices shall be rendered after final settlement information becomes available from the CAISO that identifies any CAISO Charges. At Seller’s request, Buyer shall provide Seller with an invoice detailing all Generating Facility CAISO Charges by individual CAISO Charge codes or types used by CAISO to identify individual CAISO Charges including a copy of all supplemental or supporting documentation provided by the CAISO to Buyer in the settlement process. Seller shall pay the amount of CAISO Charges Invoices on or before the later of the 20th day of each month, or tenth day after receipt of the CAISO Charges Invoice or, if such day is not a Business Day, then on the next Business Day. If Seller fails to pay a CAISO Charges Invoice within such timeframe, Buyer may offset any amounts owing to it for these CAISO Charges Invoices as set forth in Section 4.02. 6.

Disputes and Adjustments of CAISO Invoices. The Parties agree that all CAISO Charges Invoices are subject to the CAISO Tariff and may be adjusted by the CAISO, or disputed by Buyer, as Scheduling Coordinator, in accordance with the CAISO Tariff. The Parties agree that all CAISO Charges Invoices are subject to dispute between the Parties in accordance with this Agreement. Notwithstanding anything to the contrary contained in this Agreement, the Parties agree that the obligations under this Exhibit G with respect to the payment of CAISO Charges Invoices, or the adjustment of such CAISO Charges Invoices, shall survive the expiration or termination of this Agreement for a period of 365 days beyond the time period which CAISO may adjust, modify or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the CAISO Tariff.

7.

Terminating Buyer’s Designation as Scheduling Coordinator. (a)

Seller may terminate Buyer as Scheduling Coordinator: (i)

In accordance with Section 7(b) of this Exhibit G; or

(ii)

If Buyer materially fails to fulfill its obligations as Scheduling Coordinator and: (1)

Exhibit G

Seller provides advance Notice to Buyer setting forth in reasonable detail the nature of such failure and such failure is not remedied within 30 days after such Notice; provided, however, that if such failure is not reasonably capable of being remedied within such 30day period, Buyer shall have such additional time (not to exceed 120 days) as is reasonably necessary to remedy such failure, so

The contents of this document are subject to restrictions on disclosure as set forth herein. Scheduling Coordinator Services

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long as Buyer promptly commences and diligently pursues such remedy;

(iii)

(b)

Seller (A) submits to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the date of Buyer’s termination as Scheduling Coordinator, and (B) causes its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

(3)

The Parties will take any other action necessary to terminate the designation of Buyer as Scheduling Coordinator, including amending this Agreement; or

If Seller is required to elect Buyer as Scheduling Coordinator in accordance with Section 1.08, then, subject to Section 3.06(b) or 3.09(b), as applicable, by (1) providing a Notice to Buyer on or before the 60th day after Seller meets the requirements of Section 3.06(a) and 3.09(a), and (2) at least 30 days before the replacement Buyer as the Scheduling Coordinator, complying with the requirements for designating a different Scheduling Coordinator by taking all necessary actions to terminate the designation of Buyer as Scheduling Coordinator, including those actions set forth in Sections 7(b)(i) and (b)(ii) of this Exhibit G. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator.

At least 30 days before the expiration of the Term or as soon as an Early Termination Date is declared (regardless of which Party declared it), the Parties will take all actions necessary to terminate the designation of Buyer as Scheduling Coordinator as of 11:59 p.m. PPT on the Term End Date (“SC Replacement Date”). Such actions include the following: (i)

(ii)

Exhibit G

(2)

Seller shall: (1)

Submit to the CAISO a designation of a new Scheduling Coordinator to replace Buyer effective as of the SC Replacement Date; and

(2)

Cause its newly designated Scheduling Coordinator to submit a letter to the CAISO accepting the designation; and

Buyer shall submit a letter to the CAISO resigning as Scheduling Coordinator effective as of the SC Replacement Date.

The contents of this document are subject to restrictions on disclosure as set forth herein. Scheduling Coordinator Services

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Southern California Edison

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(c)

Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement Scheduling Coordinator. *** End of Exhibit G ***

Exhibit G

The contents of this document are subject to restrictions on disclosure as set forth herein. Scheduling Coordinator Services

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT H [Intentionally omitted.] *** End of Exhibit H ***

Exhibit H

The contents of this document are subject to restrictions on disclosure as set forth herein. [Intentionally omitted.]

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT I Seller’s Forecasting Submittal and Accuracy Requirements 1.

2.

General Requirements. The Parties shall abide by the Forecasting requirements and procedures described below and shall agree upon reasonable changes to these requirements and procedures from time to time as necessary to: (a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the Operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated Forecast and outage submissions.

Seller’s Forecasting Submittal Requirements for all Generating Facilities. (a)

30-Day Forecast. No later than 30 days before the Term Start Date, Seller shall provide Buyer with a Forecast for the 30-day period commencing on the start of the Term using the Web Client. If the Web Client becomes unavailable, Seller shall provide Buyer with the Forecast by e-mail or by telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N. The Forecast, and any updated Forecasts provided pursuant to this Section 2, shall:

(b)

(i)

Not include any anticipated or expected electric energy losses between the CAISO-Approved Meter and the Delivery Point; and

(ii)

Limit hour-to-hour Forecast changes to no less than 250 kWh during any period when the Web Client is unavailable. Seller shall have no restriction on hour-to-hour Forecast changes when the Web Client is available.

Weekly Update to 30-Day Forecast. Commencing on or before 5:00 p.m. PPT of the Wednesday before the first week covered by the Forecast provided pursuant to Section 2(a) of this Exhibit I, and on or before 5:00 p.m. PPT every Wednesday thereafter until the Term End Date, Seller shall update the Forecast for the 30-day period commencing on the Sunday following the weekly Wednesday Forecast update submission. Seller shall use the Web Client, if available, to supply this weekly update or, if the Web Client is not available, Seller shall provide Buyer with the weekly Forecast update by e-mailing or telephoning Buyer’s Generation Operations Center, at the e-mail address or telephone number(s) listed in Exhibit N.

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit I Seller’s Forecasting Submittal and Accuracy Requirements

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(c)

Further Update to 30-Day Forecast. As soon as reasonably practicable and commensurate with Seller’s knowledge, Seller shall provide Forecast updates related to Buyer’s Scheduled daily, hourly and real-time deliveries from the Generating Facility for any cause, including changes in Site ambient conditions, a Forced Outage, or a Real-Time Forced Outage, any of which results in a material change to the Generating Facility’s deliveries (whether in part or in whole). This updated Forecast pursuant to this Exhibit I must be submitted to Buyer via the Web Client by no later than: (i)

5:00 p.m. PPT on the day before the Trading Day impacted by the change, if the change is known to Seller at that time;

(ii)

The Hour-Ahead Scheduling Deadline, if the change is known to Seller at that time; or

(iii)

If the change is not known to Seller by the timeframes indicated in (i) or (ii) immediately above, no later than 20 minutes after Seller becomes aware of the event which caused the expected electric energy production change.

Seller’s updated Forecast must contain the following information: (w) The beginning date and time of the event resulting in the availability of the Generating Facility and expected electric energy production change;

3.

(x)

The expected ending date and time of the event:

(y)

The expected electric energy production, in MWh; and

(z)

Any other information required by the CAISO as communicated to Seller by Buyer.

Seller’s Forecasting Accuracy Requirements. If a (non-zero) Firm Contract Capacity quantity is applicable to this Agreement, then this Section 3 applies to Seller. (a)

Accuracy Metric. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate and report to Seller the monthly mean absolute error (“MAEm”) between Seller’s Day-Ahead Forecasts and the respective daily summations of Metered Energy: Forecast Error MAEm = Total Forecast

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit I Seller’s Forecasting Submittal and Accuracy Requirements

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company n

Forecast Error =



| fi – ai |

i

n

Total Forecast =

 i

fi

where: n

= the total number of hours in calendar month “m”

i

= an hour within month “m”

fi = Seller’s Day-Ahead Forecast for hour “i” ai = the quantity of (i) Metered Energy for hour “i” plus the quantity of electric energy not delivered as a result of a Real-Time Forced Outage for hour “i” (in MWh) when the Generating Facility is not PIRP-eligible, or when Buyer is not Scheduling Coordinator; or (ii) the actual available total generation capacity of the Generating Facility (in MW) when the Generating Facility is PIRP-eligible and Buyer is Scheduling Coordinator. Buyer shall report each MAEm to Seller and, upon Seller’s request, Buyer shall furnish all supporting calculations within a reasonable timeframe. Notwithstanding anything to the contrary set forth in this Section 3(a), for hour “i” for which the absolute difference between variable “fi” and variable “ai” is a number greater than zero, to the extent that such difference results from the fault or negligence of Buyer in its role as Scheduling Coordinator the value “| fi – ai |” for that hour shall be deemed to be zero. (b) Forecasting Penalty. If the MAEm for a particular month “m” is greater than 15% or if the average Forecast error for all hours of the month is greater thenthan three MW, then an “MAE Failure” will be deemed to have occurred. An MAE Failure will be waived if Seller demonstrates to Buyer’s reasonable satisfaction that the MAE Failure was the result of unexpected changes in either electrical or steam demand associated with the Site Host Load. If such MAE Failure has been waived, then that month does not count as a month in which there was an MAE Failure. For each month in which an MAE Failure has occurred, Seller shall pay a fee equal to the applicable Monthly Scheduling Fee in addition to any otherwise applicable Monthly Scheduling Fee. During each month an MAE Failure occurs, subject to the limitations of the following paragraph, Seller will continue to receive Monthly Capacity Payments for the Firm Contract Capacity based on the Firm Capacity Price and capacity payment calculations for firm capacity as set forth in Section 3 of Exhibit D. The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit I Seller’s Forecasting Submittal and Accuracy Requirements

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

If, however, an MAE Failure occurs three times in any rolling 12-month period, then starting on the first day of the calendar month immediately following the third such occurrence (such month, the “First Penalty Month”): (i)

The quantity of Firm Contract Capacity specified in Section 1.02(d) will be deemed to be zero (“Penalized Firm Contract Capacity”); and

(ii)

The quantity of As-Available Contract Capacity specified in Section 1.02(d) will be deemed increased by the quantity of Firm Contract Capacity as such quantity existed before the First Penalty Month (“Penalized As-Available Contract Capacity”).

The Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall continue to be in effect during every subsequent calendar month until there are two consecutive calendar months without an MAE Failure (including a month in which an MAE Failure has been waived). Upon such event, starting on the first day of the calendar month immediately following the second consecutive month during which Buyer does not have an MAE Failure, the Penalized Firm Contract Capacity and Penalized As-Available Contract Capacity quantities shall revert to the Firm Contract Capacity and AsAvailable Contract Capacity quantities existing before the First Penalty Month. *** End of Exhibit I ***

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit I Seller’s Forecasting Submittal and Accuracy Requirements

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT J CAISO Charges If at any time after the Term Start Date Buyer is not Scheduling Coordinator for the Generating Facility, then Buyer will not be responsible for any CAISO Charges. If at any time after the Term Start Date Buyer is Scheduling Coordinator for the Generating Facility, then Buyer shall pay all CAISO Charges and receive all CAISO Revenues; provided, however, if at any time after the Term Start Date: 1.

The CAISO implements or has implemented any sanction or penalty related to Scheduling, outage reporting or generator Operation, and any such sanctions or penalties are imposed on the Generating Facility or to Buyer as Scheduling Coordinator for the Generating Facility due solely to the actions or inactions of Seller, then such sanctions or penalties will be Seller’s responsibility;

2.

Seller or any third party dispatches any portion of the Net Contract Capacity for the benefit of any party other than Buyer or a Site host in respect of the Host Site, then Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator);

3.

Seller does not comply with: (a)

The requirements set forth in Section 3.15; or

(b)

Seller’s obligation associated with any CAISO or Transmission Provider notice or instruction (as may be communicated by Buyer as Scheduling Coordinator) to (i) increase output to the Firm Contract Capacity during a System Emergency or an Emergency Condition, or (ii) reschedule a planned outage set to occur during a System Emergency or an Emergency Condition, then

Seller shall indemnify, defend, and hold Buyer harmless against any CAISO Charges associated with any failure set forth in Sections 3(a) or 3(b) of this Exhibit J (except to the extent such CAISO Charges result from the fault or negligence of Buyer in its role as Scheduling Coordinator); or 4.

If the Generating Facility is PIRP-eligible and is not certified as a PIRP resource for any reason, then Seller shall indemnify, defend, and hold Buyer harmless against all CAISO Charges associated with the electric energy generated and delivered from the Generating Facility.

If any of Sections 1 through 4 of this Exhibit J apply and the Generating Facility is subject to an Uninstructed Deviation Penalty, Seller will not be required to pay the SDD Energy Adjustment and, instead, shall be responsible for all applicable Uninstructed Deviation Penalty charges for the Generating Facility. *** End of Exhibit J ***

Exhibit J

The contents of this document are subject to restrictions on disclosure as set forth herein. CASIO Charges

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT K Scheduling and Delivery Deviation Adjustments If Buyer is Scheduling Coordinator for the Generating Facility and if the Generating Facility is not PIRP-eligible, then Seller or Buyer, as the case may be, shall be responsible for the following SDD Adjustments with respect to the Generating Facility: 1.

SDD Energy Adjustment. An Adjustment will be calculated for each Settlement Interval in a month if the Metered Energy is either (a) less than the Performance Tolerance Band Lower Limit in any Settlement Interval or (b) greater than the Performance Tolerance Band Upper Limit in any Settlement Interval. When the SDD Energy Adjustment is negative, Seller shall make a payment to Buyer and when the SDD Energy Adjustment is positive, Seller shall receive a credit from Buyer. The SDD Energy Adjustment is calculated as follows: If A < D, then SDD Energy Adjustment= (D – A) x (EP – P) or If A > E, then SDD Energy Adjustment = (A – E) x (P – EP) Otherwise, the SDD Energy Adjustment = 0 where: A = Metered Energy for the Settlement Interval; B = Seller’s Final Energy Forecast based on the hourly forecasts made pursuant to Exhibit I corresponding to the Settlement Interval; C = Performance Tolerance Band = The greater of (a) three percent of the Seller’s Final Energy Forecast divided by the number of Settlement Intervals in such hour or (b) one (1) MWh divided by the number of Settlement Intervals in such hour; D = Performance Tolerance Band Lower Limit = (B – C); E = Performance Tolerance Band Upper Limit = (B + C); EP =

TOD Period Energy Price applicable to the Settlement Interval specified in Section 2(b) of Exhibit D; and

P = Real-Time Price for the Generator’s PNode as published by the CAISO on OASIS for the Settlement Interval.

Exhibit K

The contents of this document are subject to restrictions on disclosure as set forth herein. Scheduling and Delivery Deviation Adjustments

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

2.

SDD Administrative Charge. Seller shall make a payment to Buyer (the “SDD Administrative Charge”) for each Settlement Interval in a month if Metered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, in any Settlement Interval. The SDD Administrative Charge is calculated as follows: If A > (B + C) or A < (B – C), then: SDD Administrative Charge = (Absolute Value (B – A) – C) x Uninstructed Deviation GMC Rate. Otherwise, the SDD Administrative Charge = 0. *** End of Exhibit K ***

Exhibit K

The contents of this document are subject to restrictions on disclosure as set forth herein. Scheduling and Delivery Deviation Adjustments

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT L Physical Trade Settlement Amount This Exhibit L is only applicable when Buyer is not Scheduling Coordinator. 1.

Physical Trades Cleared in the IFM. The CAISO Revenue credited to Buyer’s account by CAISO as a result of a Physical Trade having cleared in the IFM shall be for Buyer’s account.

2.

Physical Trades not Cleared in the IFM. With respect to each calendar month “m”, as soon as practicable after the end of such month, Buyer shall calculate the Physical Trade Settlement Amount (“PTSAi”) for each hour as follows: PTSAi =

CPTi x (CPTPi – PNodei)

Where: i

=

an hour within month “m”

CPT

=

Converted Physical Trade, in MWh

CPTP

=

Converted Physical Trade Price, and

PNode

=

the Generating Facility’s PNode price, in dollars per MWh.

If the PTSAi is positive and Seller submitted the original Physical Trade in accordance with Section 3.14(s)(ii) and Exhibit I, then Buyer shall owe Seller the PTSAm for month m. In any event the PTSAi is negative, however, then Seller shall owe Buyer the PTSAi. *** End of Exhibit L ***

Exhibit L

The contents of this document are subject to restrictions on disclosure as set forth herein. Physical Trade Settlement Amount

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Southern California Edison

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT M SC Trade Settlement Amount This Exhibit M is only applicable when Buyer is not Scheduling Coordinator. If, in any Settlement Interval, a Generating Facility’s Scheduled Amount differs from the Generating Facility’s Metered Energy by more than the SC Trade Tolerance Band, then Seller shall be subject to a payment adjustment calculated by Buyer in accordance with the procedures and formulas set forth below. (1)

Under-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy, and the Real-Time Price is greater than the DayAhead Price payable during the Settlement Interval, then Seller’s monthly payment amount shall be reduced by each Under-Scheduling Settlement Interval Adjustment Amount calculated by the following formula: UNDER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [A – B] x [D – C] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No under-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount plus the SC Trade Tolerance Band is less than the Metered Energy if, during such Settlement Interval, the Real-Time Price is equal to or less than the Day-Ahead Price payable during the Settlement Interval. (2)

Over-Scheduling Adjustment. If during any Settlement Interval the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy, and the Real-Time Price is less than the DayAhead Price payable during the Settlement Interval; Then Seller’s monthly payment amount shall be reduced by each Over-Scheduling Settlement Interval Adjustment Amount calculated by the following formula:

Exhibit M

The contents of this document are subject to restrictions on disclosure as set forth herein. SC Trade Settlement Amount

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

OVER-SCHEDULING SETTLEMENT INTERVAL ADJUSTMENT AMOUNT = [B – A] x [C – D] Where A =

The Metered Energy in the Settlement Interval being calculated.

B =

The Scheduled Amount in the Settlement Interval being calculated.

C =

Day-Ahead Price for the Settlement Interval being calculated in $/kWh.

D =

Real-Time Price for the Settlement Interval being calculated in $/kWh.

No over-scheduling adjustment shall be assessed against Seller for a Settlement Interval in which the Scheduled Amount is greater than the SC Trade Tolerance Band plus the Metered Energy if, during such Settlement Interval, the Real-Time Price is greater than or equal to the Day-Ahead Price payable during the Settlement Interval. *** End of Exhibit M ***

Exhibit M

The contents of this document are subject to restrictions on disclosure as set forth herein. SC Trade Settlement Amount

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Southern California Edison

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT N Notice List [SELLER’S NAME] SYCAMORE COGENERATION COMPANY

SOUTHERN CALIFORNIA EDISON COMPANY

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

All Notices are deemed provided in accordance with Section 9.07 if made to the address, facsimile numbers or e-mail addresses provided below:

Contract Sponsor: Attn: Executive Director Street: P.O. Box 80478 City: Bakersfield, California 93380 Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected]

Contract Sponsor: Attn: Vice President of Renewable and Alternative Power Street: 2244 Walnut Grove Avenue City: Rosemead, California 91770 Phone: Facsimile:

Reference Numbers: Duns: 18-507-4887 Federal Tax ID Number: 95-4014893

Reference Numbers: Duns: 006908818 Federal Tax ID Number: 95-1240335

Contract Administration: Attn: Business Manager Phone: (661) 615-4675 Facsimile: (661) 615-4610 E-mail: [email protected]

Contract Administration: Attn: Phone: Facsimile: E-mail:

Forecasting: Attn: Control Room Phone: (661) 615-4704 Facsimile: (661) 615-4664 E-mail: [email protected]

Forecasting: Attn: Phone: 626.307.4420 Facsimile: E-mail: [email protected]

Day-Ahead Forecasting: Phone: (661) 615-4704 Facsimile: (661) 615-4664 E-mail: [email protected]

Day-Ahead Scheduling: Attn: Manager of Day-Ahead Operations Attn: Scheduling Desk Phone: 626.307.4425 or 626.307.4420 Facsimile: 626.307.4413 E-mail: [email protected]

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit N

Notice List

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Real-Time Forecasting: Phone: (661) 615-4639 Facsimile: (661) 615-4610 E-mail: [email protected]

Real-Time Scheduling: Attn: Manager of Real-Time Operations Attn: Operations Desk Phone: 626.307.4405 or 626.307.4453 Facsimile: 626.307.4416 E-mail: [email protected] Payment Statements: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: CAISO Charges and CAISO Sanctions: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Payments: Attn: Power Procurement - Finance Phone: Facsimile: E-mail: Wire Transfer: BNK: JP Morgan Chase Bank ABA: 021000021 ACCT: 323-394434 Credit and Collateral: Attn: Manager of Credit and Collateral Phone: Facsimile: Email:

Payment Statements: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] CAISO Charges and CAISO Sanctions: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Payments: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Wire Transfer: BNK: Chase Manhattan ABA: 021-0000-21 ACCT: 910-2588-705 Credit and Collections: Attn: Accounting Department Phone: (661) 615-4630 Facsimile: : (661) 615-4610 E-mail: [email protected] With additional Notices of an Event of Default or Potential Event of Default to: Attn: Executive Director Phone: (661) 615-4630 Facsimile: (661) 615-4610 E-mail: [email protected] Guarantor: N/A Attn: Phone: Facsimile: E-mail:

With additional Notices of an Event of Default or Potential Event of Default to: Attn: Manager SCE Law Department Power Procurement Section Phone: Facsimile: Email: Guarantor: N/A Attn: Phone: Facsimile: E-mail:

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit N

Notice List

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Lender: N/A Attn: Phone: Facsimile: E-mail:

Lender: N/A Attn: Phone: Facsimile: E-mail: *** End of Exhibit N ***

The contents of this document are subject to restrictions on disclosure as set forth herein. Exhibit N

Notice List

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT O [Intentionally omitted.] *** End of Exhibit O ***

Exhibit O

The contents of this document are subject to restrictions on disclosure as set forth herein. [Intentionally omitted.]

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT P [Intentionally omitted.] *** End of Exhibit P ***

Exhibit P

The contents of this document are subject to restrictions on disclosure as set forth herein. [Intentionally omitted.]

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT Q [Intentionally omitted.] *** End of Exhibit Q ***

Exhibit Q

The contents of this document are subject to restrictions on disclosure as set forth herein. [Intentionally omitted.]

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT R Outage Schedule Submittal Requirements 1.

General Requirements. The Parties shall abide by the Outage Schedule Submittal Requirements described below and shall agree upon reasonable changes to these requirements and procedures from time to time, as necessary to:

2.

(a)

Comply with the CAISO Tariff;

(b)

Accommodate changes to their respective generation technology and organizational structure; and

(c)

Address changes in the operating and Scheduling procedures of Seller, Buyer and the CAISO, including automated forecast and outage submissions.

Seller’s Availability Forecasting Submittal Requirements for all Generating Facilities. Seller shall submit maintenance and planned outage schedules in accordance with the following schedule: (a)

No later than January 1st, April 1st, July 1st and October 1st of each Term Year, and at least 60 days before Parallel Operationthe Term Start Date, Seller shall submit to Buyer its schedule of proposed planned outages (“Outage Schedule”) for the subsequent twenty four-month period using a Buyer-provided web-based system or an e-mail address designated by Buyer (“Web Client”).

(b)

Seller shall provide the following information for each proposed planned outage: (i)

Start date and time;

(ii)

End date and time; and

(iii)

Capacity online, in MW, during the planned outage.

(c)

Within 20 Business Days after Buyer’s receipt of an Outage Schedule, Buyer shall notify Seller in writing of any request for changes to the Outage Schedule, and Seller shall, consistent with Prudent Electrical Practices, accommodate Buyer’s requests regarding the timing of any planned outage.

(d)

Seller shall cooperate with Buyer to arrange and coordinate all Outage Schedules with the CAISO.

Exhibit R

The contents of this document are subject to restrictions on disclosure as set forth herein. Outage Schedule Submittal Requirements

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Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(e)

In the event a condition occurs at the Generating Facility which causes Seller to revise its planned outages, Seller shall provide Notice to Buyer, using the Web Client, of such change (including, an estimate of the length of such planned outage) as required in the CAISO Tariff after the condition causing the change becomes known to Seller.

(f)

Seller shall promptly prepare and provide to Buyer upon request, using the Web Client, all reports of actual or forecasted outages that Buyer may reasonably require for the purpose of enabling Buyer to comply with Section 761.3 of the California Public Utilities Code, the CAISO Tariff or any Applicable Law mandating the reporting by investor owned utilities of expected or experienced outages by electric energy generating facilities under contract to supply electric energy. *** End of Exhibit R ***

Exhibit R

The contents of this document are subject to restrictions on disclosure as set forth herein. Outage Schedule Submittal Requirements

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RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT S TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements Introduction. Subject to Section 4.04 and Exhibit D, this Exhibit S sets forth the formulas and methodology that Buyer will use in order to calculate the TOD Period Energy Price, and also sets forth Seller’s Greenhouse Gas emissions reporting requirements. 1. TOD Period Energy Price. Subject to Section 2 of this Exhibit S, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable time-period in accordance with the following formula: TOD Period Energy Price $/kWh = ((Applicable HR * BTGP/1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = The Heat Rate for the specified time-period, per the following table: Calendar Year(s) 2011 2012 January 1, 2013 through December 31, 2014 January 1, 2015 until the termination of this Agreement

Heat Rate (Btu/kWh) 8,700 8,225 8,125 Market Heat Rate

BTGP = Calendar month Burner Tip Gas Price ($/MMBtu), per the Decision and CPUC Resolution E-4246; VOM = Calendar month avoided variable O&M ($/kWh), per the Decision and CPUC Resolution E-4246; GHG Charges = All taxes, charges or fees assessed with the implementation and regulation of Greenhouse Gas emissions with respect to the Generating Facility imposed by any Governmental Authority, such as the CARB’s AB 32 Cost of Implementation Fee (as defined in Title 17 C.C.R. §95200). For example, if the charges are assessed on but not included in fuel consumption or gas costs, the Applicable HR or Burner Tip Gas Price will be used to derive the dollars per kilowatt-hour charge. On January 1, 2015 or the commencement of the First Compliance Period, the GHG Charges will equal zero in the above formula; TOU (i.e., time-of-use) = Throughout the Term, the applicable time-of-use factors are as follows:

Exhibit S

The contents of this document are subject to restrictions on disclosure as set forth herein. TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

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Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

On-Peak Mid-Peak Off-Peak Super Off-Peak

Summer 1.4251 see below 0.8526 N/A

Winter N/A 1.2185 see below 0.7760

Summer Mid-Peak = (Total # hours in month - (1.4251 * # of Summer On-Peak hours in month) - (0.8526 * # of Summer Off-Peak hours in month)) / # of Summer Mid-Peak hours in month Winter Off-Peak = (Total # hours in month - (1.2185 * # of Winter Mid-Peak hours in month) - (0.7760 * # of Winter Super Off Peak hours in month)) / # of Winter Off-Peak hours in month LA (i.e., hourly location adjustment, in $/kWh) = LMPQF - LMPTrading Hub Where the hourly location adjustment (i.e., LA) will be based on the hourly Day-Ahead prices and actual hourly generation by the Generating Facility for delivery to Buyer as follows: LMPQF (in $/kWh) = The hourly Day-Ahead Locational Marginal Price at the point of interconnection with the CAISO Controlled Grid associated with the Generating Facility; and LMPTrading Hub (in $/kWh) = The hourly Day-Ahead Locational Marginal Price of the trading hub where the Generating Facility is located (i.e., SP15 Existing Zone Generation Trading Hub (formerly SP15), NP15 Existing Zone Generation Trading Hub (formerly NP15), or ZP26 Existing Zone Generation Trading Hub (formerly ZP26), as applicable, or any successor thereto). 2. TOD Period Energy Price during the Floor Test Term. (a) If there is a cap-and-trade program in California for the regulation of Greenhouse Gas, as established by the CARB (or by a different Governmental Authority pursuant to federal or state legislation), then, during the Floor Test Term, the TOD Period Energy Price will be the higher of the following two formulas (the “GHG Floor Test”): (i) TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA

Exhibit S

The contents of this document are subject to restrictions on disclosure as set forth herein. TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 2

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A; BTGP ($/MMBtu) = As set forth above; VOM ($/kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. OR (ii) TOD Period Energy Price $/kWh = ((Applicable HR * (BTGP + GHG Allowance Price) /1,000,000) + VOM) * TOU + LA + GHG Charges Where: Applicable HR = (A) 8,225 Btu/kWh through December 31, 2012; (B) 8,125 Btu/kWh from January 1, 2013 through December 31, 2014; and (C) Actual HR from January 1, 2015 until the end of the Floor Test Term; BTGP ($/MMBtu) = As set forth above; GHG Allowance Price ($/MMBtu) = Allowance Cost ($/MT) * 117lbs of Greenhouse Gas per MMBtu / 2,204.6 lbs per MT Where: Allowance Cost ($/MT) = The cost of one Allowance, determined using the GHG Auction clearing price from the latest GHG Auction that has taken place during the calendar quarter immediately preceding the date that Buyer’s payment is due to Seller; provided, however, that if there is no GHG Auction held during the applicable time-period, then the Allowance Cost is determined in accordance with Section 2(c) of this Exhibit S; VOM ($/kWh) = As set forth above; GHG Charges ($/kWh) = As set forth above;

Exhibit S

The contents of this document are subject to restrictions on disclosure as set forth herein. TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 3

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

TOU = As set forth above; and LA ($/kWh) = As set forth above. (b) Free Allowance Reporting and Allocation. If, at any time, Buyer makes a monthly payment to Seller utilizing the GHG Floor Test formula set forth in Section 2(a)(ii) of this Exhibit S, then Buyer shall deduct from the monthly payment to Seller for the applicable month the value of the Free Allowances disclosed in and based on all Free Allowance Notices that have not already been applied to a prior payment to Seller; provided, however, that if Buyer, using reasonable efforts, is unable to process such payment adjustment for the applicable month, then Buyer shall make such payment adjustment to the next monthly payment due to Seller. For any month that Buyer utilizes the formula set forth in Section 2(a)(ii) of this Exhibit S to make a monthly payment to Seller, Buyer shall maintain a record of the value and quantity of all Free Allowances disclosed in the Free Allowance Notices, if any, and shall deduct the value of such Free Allowances to any subsequent monthly payment due to Seller where Buyer calculates such monthly payment utilizing the formula set forth in Section (2)(a)(ii) of this Exhibit S until such time that the value of all such Free Allowances are expended. In order for Buyer to make the payment adjustment set forth in the immediately preceding paragraph, Seller agrees to deliver to Buyer, within twenty (20) days of receiving any Free Allowances, a Free Allowance Notice for the applicable month, which Free Allowance Notice must include all Additional GHG Documentation. Buyer shall value any such Free Allowances using the same methodology Buyer uses in valuing the Allowance Cost, as set forth above. (c) Determining Allowance Costs under the GHG Floor Test if there is No GHG Auction. This Section 2(c) is applicable if no GHG Auction has been held during the time-period for which the Allowance Cost variable set forth in Section 2(a) of this Exhibit S is to be determined. In such an instance, publicly available indices will be used to determine the price for the applicable period. If no such indices exist, Buyer will meet with the Trade Organizations to negotiate in good faith to reach an agreement on setting the Allowance Cost variable. If, after negotiating for fifteen (15) Business Days, Buyer and the Trade Organizations have not reached an agreement on setting the Allowance Cost variable, then Buyer and the Trade Organizations shall each select, within fifteen (15) days after such failed negotiations, price quotations for the cost of one Allowance, as set forth in two (2) different Reference Market-Makers, for a total of four (4) price quotations. The Allowance Cost variable for the applicable time-period will be determined by taking the average of the four (4) price quotations so selected by Buyer and the Trade Organizations. Seller agrees and acknowledges that it shall be bound by any agreement as to the Allowance Cost variable between Buyer and the Trade Organizations, in accordance with the foregoing.

Exhibit S

The contents of this document are subject to restrictions on disclosure as set forth herein. TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 4

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

(d) TOD Period Energy Price from the end of the Floor Test Term. As of end of the Floor Test Term until the termination of this Agreement, Buyer shall calculate the TOD Period Energy Price for electric energy delivered to Buyer by Seller during the applicable timeperiod in accordance with the following formula: TOD Period Energy Price $/kWh = ((Market Heat Rate * BTGP/1,000,000) + VOM) * TOU + LA Where: Market Heat Rate (Btu/kWh) = As defined in Exhibit A; BTGP ($/MMBtu) = As set forth above; VOM ($kWh) = As set forth above; TOU = As set forth above; and LA ($/kWh) = As set forth above. (e) Seller’s Responsibility. Other than Buyer’s payment to Seller for GHG Compliance Costs and GHG Charges as set forth in payment formulas above, Seller is solely responsible for all GHG Compliance Costs and all other costs associated with implementation and regulation of GHG emissions with respect to Seller or the Generating Facility. 3. Reporting Requirements. (a) From the Effective Date through the Term End Date (and for any period following the termination of this Agreement to the extent relating back to the Term), Seller shall provide to Buyer the following information (together, the “Annual GHG Reports”): (i) On or before the fifth (5th) Business Day following Seller’s timely submission to the CARB (or any other authorized Governmental Authority having jurisdiction in California) of the CARB Mandatory GHG Emissions Annual Report, or such other annual report submitted to the CARB, detailing the Greenhouse Gas emissions of the Generating Facility for the applicable calendar year (as verified by an independent

Exhibit S

The contents of this document are subject to restrictions on disclosure as set forth herein. TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 5

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

third party, if applicable) (the “CARB Annual Report”), Seller shall deliver such CARB Annual Report to Buyer; and (ii) To the extent not set forth in the CARB Annual Report (or if Seller is no longer required to submit the CARB Annual Report for any reason), then Seller shall submit to Buyer, along with the CARB Annual Report (or, if Seller is no longer required to submit the CARB Annual Report for any reason, then on the sixtieth (60th) Business Day following the end of the applicable calendar year), the following information for the applicable calendar year, which, in each case, must be verifiable and of settlement quality: (1) the Useful Thermal Energy Output of the Generating Facility; and (2) total fuel usage of the Generating Facility; and (3) the total amount of Greenhouse Gas emissions attributable to the Generating Facility, the electric energy used to serve the Site Host Load, and the Useful Thermal Energy Output of the Generating Facility; and (4) the total electric energy produced by the Generating Facility, the electric energy used to serve the Site Host Load, and the electric energy delivered to Buyer; and (5) the number of Allowances (including Free Allowances) held or surrendered by Seller for such calendar year during any period where the TOD Period Energy Price is calculated based on the GHG Floor Test. (b) If Buyer requires any other information not delineated in Section 3(a) of this Exhibit S in order to comply with any Greenhouse Gas emissions reporting requirements adopted by the CARB or by any other Governmental Authority and imposed on Buyer (other than the information that Seller must provide in accordance with Section 3(c) of this Exhibit S), then Buyer shall promptly meet and confer with the Trade Organizations regarding such other information that Buyer requires and negotiate in good faith to reach a mutually acceptable agreement. Seller agrees and acknowledges that it shall be bound by any agreement between Buyer and the Trade Organizations, in accordance with the foregoing. (c) Buyer will review the Annual GHG Reports described in this Section 3 to determine if there is any discrepancy in the payments made by Buyer to Seller for GHG Compliance Costs during the course of the applicable calendar year. To the extent Buyer determines that there is any such discrepancy, (i) if Buyer owes Seller an additional payment for GHG Compliance Costs, then Buyer shall make such additional payment in a subsequent monthly payment to Seller under this Agreement, or (ii) if Seller owes Buyer a payment refund for GHG Compliance Costs, then Buyer shall offset such payment refund amount in a subsequent monthly payment to Seller under this Agreement. If this Agreement terminates before Buyer is able to make such additional payment for GHG Compliance Costs or offset such GHG Compliance Costs payment refund from Seller’s monthly payments, as applicable, then Buyer or Seller, as applicable, shall pay all remaining

Exhibit S

The contents of this document are subject to restrictions on disclosure as set forth herein. TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 6

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

payment amounts due within the thirty- (30) day period after the termination of this Agreement. (d) To the extent that the information provided by the disclosing Party in accordance with this Section 3 is Confidential Information, the receiving Party shall treat such Confidential Information with the same degree of care that it currently treats the data and information provided by Qualifying Cogeneration Facilities under the existing Qualifying Cogeneration Facilities monitoring compliance program. 4. Market Disruption Event. Unless this Agreement has terminated, if, on or after the date that the Market Heat Rate applies to and is used in the calculation of the TOD Period Energy Price and until the termination of this Agreement, there occurs a Market Disruption Event, then the Market Heat Rate for the affected Trading Day(s) must be determined by reference to the Market Heat Rate for the first Trading Day thereafter on which no Market Disruption Event exists; provided, however, that if the Market Heat Rate is not so determined within five (5) Trading Days after the Market Disruption Event occurred or existed, then Buyer shall meet with the Trade Organizations to negotiate in good faith to reach an agreement on a Market Heat Rate (or a method for determining a Market Heat Rate), and if Buyer and the Trade Organizations have not so agreed on or before the twelfth (12th) Trading Day after which the Market Disruption Event occurred or existed, then the Market Heat Rate will be determined in good faith by taking the average of the price quotations for electric energy and relevant Trading Days that are obtained from no more than two (2) Reference Market-Makers selected by each of Buyer and the Trade Organizations (for a total of four (4) price quotations). Seller hereby agrees and acknowledges that it shall be bound by any agreement as to a Market Heat Rate (or a method for determining a Market Heat Rate) between Buyer and the Trade Organizations, in accordance with the foregoing. *** End of Exhibit S ***

Exhibit S

The contents of this document are subject to restrictions on disclosure as set forth herein. TOD Period Energy Price Calculation; Greenhouse Gas Reporting Requirements

Page 7

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

EXHIBIT T QF Efficiency Monitoring Program – Cogeneration Data Reporting Form 2244 Walnut Grove Ave, Rosemead, CA 91770 QF Efficiency Monitoring Program Administrator, (626) 302-9110 [email protected] [PrevYear] I.

Name and Address of Project Name: Street: City: ID No.: ________

II. In Operation: Yes

State:

Zip Code:

Generation Nameplate (KW): __________________ No

III. Can your facility dump your thermal output directly to the environment?

Yes

No

IV. Ownership Ownership

Name

Address

(%)

1 2 3 4 5

Utility Y N Y N Y N Y N Y N

V. [PrevYear] Monthly Operating Data



Indicate the unit of measure used for your useful thermal output if other than mBTUs: BTUs Therms mmBTUs



If Energy Input is natural gas, use the Lower Heating Value (LHV) as supplied by Gas Supplier. Useful Power Output (kWh)

Energy Input (Therms)

Useful Thermal Output (mBtu)

JAN Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Yearly Total

Exhibit T Form

The contents of this document are subject to restrictions on disclosure as set forth herein. QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

Southern California Edison

Confidential Information

RAP ID #[Number], [Seller’s Name]2810, Sycamore Cogeneration Company

*** End of Exhibit T ***

Exhibit T Form

The contents of this document are subject to restrictions on disclosure as set forth herein. QF Efficiency Monitoring Program – Cogeneration Data Reporting

Page 1

Document comparison by Workshare Professional on Friday, October 12, 2012 4:23:09 PM Input: Document 1 ID Description

Document 2 ID

Description Rendering set

file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\~Settlement PPAs\Transition PPA\Transition PPA [SCE].doc Transition PPA [SCE] file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\Transition Contract Applications\2801 & 2058 - KRCC & Sycamore\Subsequent PPAs\Sycamore Subsequent PPA\Internal Drafts\20121012\20121012 Sycamore Transition PPA.DOC 20121012 Sycamore Transition PPA standard

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Total changes

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN [Click here to enter Counterparty.]SYCAMORE COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY

This confirmation letter and the appendices attached hereto and incorporated herein (“Confirmation”) confirms the Transaction between [Counterparty]Sycamore Cogeneration Company (“Seller” or “[Shortname]Sycamore”) and Southern California Edison Company (“Buyer” or “SCE”) dated as of [Date]October 15, 2012 (“Confirmation Effective Date”) regarding the sale and purchase of the Product, as such term is defined below in Section 1.5, in accordance with and subject to the terms and provisions of this Confirmation, the EEI Master Power Purchase & Sale Agreement, together with the Cover Sheet (the “Transition Cover Sheet”), any amendments and annexes thereto between Seller and SCE dated as of [Date] (“October 15, 2012 (“Transition Master Agreement”), and Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement.” Capitalized terms used but not defined in this Confirmation shall have the meanings ascribed to them in the Transition EEI Agreement or the Tariff. If any term in this Agreement conflicts with the Tariff, the definition set forth in this Agreement shall supersede. RECITALS A.

Seller owns and operates Generating Unit # 2 and Generating Unit # 4, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement.

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement.

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition RA Confirmation and the Transition PPA. ARTICLE 1 TRANSACTION DEFINITIONS

1.1

Seller

[Counterparty].Sycamore Cogeneration Company. 1.2

Buyer

SCE. 1.3

Term

The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied; provided, however, that: (i) before the commencement of the Delivery Period, SCE must have obtained, in its sole discretion or waived, CPUC Approval, and (ii) before the commencement of the Delivery Period must commence within 24 months of the Confirmation Effective Date, FERC Approval as set forth in the

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Transition PPA must have been obtained. 1.4

Delivery Period

The Delivery Period shall be as set forth in Appendix 3.1(a) unless terminated earlier in accordance with the terms of this Agreement.“Delivery Period” commences on the later of (a) October 15, 2012, or (b) the date when both CPUC Approval and FERC Approval have been obtained; provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition PPA and Transition RA Confirmation have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), and ends the date that is immediately prior to the commencement of the ‘Delivery Period’ under and as defined in the RFO Agreement, which shall be no later than June 30, 2014 (the “Delivery Period End Date”); provided, however if ‘CPUC Approval’ (as defined in the RFO Agreement) and/or ‘FERC Approval’ (as defined in the RFO Agreement) of the RFO Agreement are not obtained prior to June 30, 2014, through no fault of Seller, then the Delivery Period End Date shall be June 30, 2015. 1.5

Product

Capacity, Energy, Ancillary Services, and any other product derived from or associated with each Generating Unit, including any Green Attributes associated with the Capacity, Energy and Ancillary Services [that are in excess of the Green Attributes used, or retained for future use, by Seller or a Site Host, both in connection with the Host Site to meet a known or established, at the point in time when the Green Attributes are to be used or retained, obligation under applicable law] (collectively, the “Product”). During the Delivery Period, Seller shall sell and deliver, and SCE shall purchase and receive, the Product, subject to the terms and conditions of this Confirmation.; provided, however, that Seller’s Allowances shall be treated in accordance with Article 20. Seller represents, warrants, and covenants that it will deliver the Product to SCE free and clear of all liens, security interests, claims, and encumbrances. Seller shall not substitute or purchase the Product or any portion of the Product from any other generating resource or from the market for delivery hereunder. [SCE Internal Comment: use bracketed language for facilities with host load (i.e., hybrids).] 1.6

Energy Delivery Point

The Energy Delivery Point shall be as described and set forth in the single-line diagram of grid interconnection attached hereto as Appendix 1.6. Except as otherwise set forth in this Confirmation, Seller shall be responsible for all charges and penalties associated with the operation of the Generating Units and transmission of Energy up to and including the Energy Delivery Point, and SCE shall be responsible for all charges and penalties associated with receiving and transmitting Energy after and from the Energy Delivery Point. Title, possession, and risk of loss related to Energy shall transfer from Seller to SCE after the Energy Delivery Point. In the event of a failure by Seller to deliver the Product to the Energy Delivery Point, Article Four of the Transition Master Agreement shall not apply. The Energy Delivery Point specified herein is the Product’s “Delivery Point” for this Transaction for purposes of the Transition EEI Agreement. 1.7

Intentionally deleted.Deleted

1.8

Generating Units

Each Generating Unit and its applicable description are set forth in Section A and Section B of Appendix 1.8. 1.9

No Change to Other Agreements

Notwithstanding anything to the contrary in this Confirmation, Seller acknowledges and agrees that and SCE each acknowledge and agree that with respect to the Generating Units which are subject to the obligations under the Agreement, the Transition RA Confirmation and the Transition PPA, any other agreement between itSeller and SCE, including any interconnection agreement, is separate and apart from thisthe Agreement, the Transition RA

2

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Confirmation and the Transition PPA, such that no other agreement shall modify or add to the Parties’ obligations under the Transition EEI Agreement or this Confirmation, and that no Party’s breach under such other agreement shall excuse a Party’s nonperformance under the Agreement, except as otherwise specifically provided for under this AgreementConfirmation.

ARTICLE 2 PURCHASE AND SALE OF PRODUCT 2.1

Exclusivity

During the Delivery Period, SCE shall have the exclusive right to the Product purchased by SCE hereunder, and all benefits derived therefrom, including the exclusive right to use, market, or sellresell the Product (or any portion thereof) purchased hereunder and the right to all revenues generated from the use, saleresale, or marketing of such Product, and Seller may not sell, assign, or otherwise transfer, or commit to sell, assign, or otherwise transfer, the Product (or any portion thereof) or any benefits derived therefrom, to any party other than SCE. In addition, SCE shall have the ability to dispatch each Generating Unit to its PMax at the instruction of the CAISO and subject to the Operating Restrictions applicable to such Generating Unit and shall be entitled to all benefits of such dispatch including all revenues associated with such capacity, energy or ancillary services up to and including the Generating Unit’s PMax. 2.2

Ownership

Seller shall maintain ownership of, and exclusive demonstrable rights to, each of the Generating Units throughout the Term. ARTICLE 3 COMPENSATION AND AVAILABILITY 3.1

Compensation (a)

Monthly Capacity Payment: For each Generating Unit, SCE shall make the Monthly Capacity Payment, payable in arrears, to Seller. The Monthly Capacity Payment for each month of the Delivery Period is set forth in Section C of Appendix 3.1(a), and is subject to reduction in accordance with this Confirmation, including Sections 3.2 and 3.3 below. If the Monthly Capacity Payment is reduced in accordance with this Confirmation, SCE shall make the Reduced Monthly Capacity Payment in lieu of the Monthly Capacity Payment.

(b)

Variable O&M Payment: SCE shall pay Seller a monthly Variable O&M Payment, calculated as follows: n

Variable O&M Paymentm = Variable O&M Chargey * where:

 i

Qualifying Delivered Energyi

Variable O&M Chargey is set forth in Appendix 3.1(b) m = the relevant month within the Delivery Period being calculated y = the Contract Year corresponding to month “m”

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” (c)

Start-Up Charge: SCE shall pay for the Start-Up Fuel, the Start-Up Charge and the Start-Up Aux Charge for each Start-Up unless specified otherwise in this Confirmation. In addition to all Energy produced after a Start-Up, all Energy produced prior to the Generating Unit achieving a Start-Up during the respective start-up cycle shall be for SCE’s account.

(d)

(i)

If SCE aborts a start-up before the Generating Unit achieves full Start-Up, then SCE shall [a] pay for any natural gas consumed by the Generating Unit in connection with such aborted start-up, up to the applicable quantity of the Start-Up Fuel, [b] pay the Start-Up Charge and [c] pay the portion of the Start-Up Aux Charge that is proportional to [i] the amount of Start-Up Aux Energy (MWh) required from the beginning of the Start-Up to the time when such Start-Up was aborted as compared to [ii] the applicable Start-Up Time, provided that such payment shall not exceed the applicable Start-Up Aux Charge.

(ii)

If theany Generating Unit is unable to generate or deliver Energy to the Energy Delivery Point after a Start-Up, but before the next scheduled shutdown of thesuch Generating Unit for any reason other than a Force Majeure, SCE is not responsible for any charges under this Section 3.1(c) associated with the next Start-Up.

Transition Costs: SCE shall compensate Seller for the Transition Fuel and pay the applicable Transition Cost for each MSG Transition unless specified otherwise in this Confirmation. All Energy produced by the Generating Unit during the respective transition shall be for SCE’s account. Compensation for Transition Fuel will be included in the Fuel Payment.(e) Fuel Payment: SCE shall pay to Seller a “Fuel Payment” equal to the sum of all Gas Commodity Costs, as defined in 3.1(ed)(vi) below, for all applicable calendar days during a calendar month during the Delivery Period plus all Transport Costs, if any, for the applicable calendar month. For purposes of calculating the Fuel Payment, the following definitions shall be used: (i)

Gas Index: The index price expressed in $/MMBTUMMBtu for the applicable flow date published by Platts Gas Daily (in the internet publication currently accessed through www.platts.com) in the table entitled “Daily price survey” under the heading “Citygates” for “Kern River, delivered” under the column “Midpoint” for “SoCalGas Citygate”plus $0.01/MMBtu. For the purposes of calculating the Fuel Payment, the Gas Index will be applied to Settlement Intervals on a calendar day basis with each day starting at hour ending 01:00 and not on a Gas Day basis. If the Gas Index ceases to be published, the Parties agree to deem the loss of the Gas Index a “Market Disruption Event” as defined in the Transition Master Agreement and follow the provisions outlined in Section 3.4 of the Transition Master Agreement.

(ii)

Gas Trading Day: The calendar day on which natural gas is traded corresponding to the applicable Gas Index. For example, in the absence of Holidays, a Gas Trading Day on a Monday reflects the day-ahead price applicable to gas flow on Tuesday. A Gas Trading Day on a Friday, in the absence of a Holiday, reflects the price for gas flow on Saturday, Sunday, and Monday.

(iii)

Required Natural Gas Quantity: The Required Natural Gas Quantity for each calendar day shall be expressed in MMBtu and equal to the sum of: [a]

the quantity of natural gas required for each Settlement Interval of the calendar day, calculated by multiplying: (1)

MWh of Qualifying Delivered Energy in such Settlement Interval by

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(2)

[b]

the lesser of [i] the Heat Rate specified in Appendix 5.3 applicable to the product of the Scheduled Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour, or [ii] the Heat Rate specified in Appendix 5.3 applicable to the product of the Qualifying Delivered Energy for such Settlement Interval and the number of Settlement Intervals in one (1) hour; and

any Start-Up Fuel required during the relevant calendar day; provided that in the event the duration of a Start-Up extends past one calendar day, then all of the Start-Up Fuel will be allocated to the calendar day associated with the first nonzero hourly schedule; and [c] any Transition Fuel required for all MSG Transitions in the relevant calendar day; provided that in the event the duration of an MSG Transition extends past one calendar day, then all of the Transition Fuel shall be allocated to the calendar day associated with the first non-zero hourly power schedule.

(iv)

Day Ahead Gas Quantity: The quantity of natural gas (expressed in MMBtu), if any, determined by SCE on each Gas Trading Day for an estimated dispatch on all calendar days associated with such Gas Trading Day. For example, in the absence of a Holiday, the Day-Ahead Gas Quantities for Saturday, Sunday, and Monday shall be calculated by SCE and provided to Seller on the immediately preceding Friday, and the Day-Ahead Gas Quantity for Tuesday shall be calculated by SCE and provided to Seller on the immediately preceding Monday.

(v)

Adjustment Gas Quantity: The Adjustment Gas Quantity for each calendar day shall equal the Required Natural Gas Quantity minus the Day-Ahead Gas Quantity corresponding to the applicable calendar day.

(vi)

Gas Commodity Cost: The Gas Commodity Cost shall equal the sum of the Day Ahead Gas Cost and Adjustment Gas Cost

(vii)

Day-Ahead Gas Cost: The Day-Ahead Gas Cost shall equal the Day-Ahead Gas Quantity multiplied by the applicable Gas Index for such Day-Ahead Gas Quantity.

(viii)

Adjustment Gas Cost: If the Adjustment Gas Quantity for a calendar day is:

(ix)

(a)

positive, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index published for and on the next Gas Trading Day immediately followingassociated with the applicable Operating Day plus $0.35/MMBtu; or

(b)

negative, then the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the lower of the Gas Index (i) used for the Day-Ahead Gas Cost, or (ii) published for the next Gas Trading Day immediately following the applicable Operating Day; unless the Generating Unit(s) had a Forced Outage, that renders the entire unit(s) unavailable, declared for any Settlement Interval. In such cases, the Adjustment Gas Cost shall equal the Adjustment Gas Quantity multiplied by the Gas Index used for the Day-Ahead Gas Cost, from the first date of the occurrence of the Forced Outage up to and including the date when the next Generating Unit Start-Up is completed.

Transport Cost: Transport Cost shall mean the sum of the following two SoCalGas rate components (or any additional, replacement or successor components mutually agreed to in writing by the Parties) for transportation of natural gas to the Generating Unit’s SoCalGas Billing Meter expressed in $/MMBtu: (a)

the applicable rate set forth in the SoCalGas Transportation Contract, and

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(b)

if applicable, Transported Gas Municipal Surcharge (G-MSUR), as set forth in SoCalGas Monthly Commercial/Industrial Rate Schedule Summary.

Furthermore, Seller agrees that it is solely responsible for the “Surcharge to Fund the PUC Reimbursement Account” that is set forth in SoCalGas Rate Schedule No. G-SRF. Seller bears sole responsibility for obtaining an exemption from SoCalGas for the Rate Schedule No. G-SRF and Seller shall pay all or any portion of the surcharge for which it does not obtain the exemption. SCE retains no liability for the surcharge and Seller shall indemnify, defend, and hold SCE harmless against any costs or losses of SCE resulting from the surcharge set forth in Rate Schedule No. G-SRF. 3.2

Availability (a)

Capacity Payment Reduction. If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), (i) the Available Capacity of a Generating Unit is less than its Contract Capacity in any Settlement Interval in a month during the Delivery Period, or (ii) the Qualifying Delivered Energy from such Generating Unit is less than the Performance Tolerance Band Lower Limit in any Settlement Interval in a month during the Delivery Period, then the Capacity Payment Reduction for the affected Generating Unit for that month will be calculated as follows: (i)

For each Settlement Interval in the month, the “Price-Weighted Capacity Availability” is calculated as follows: Price-Weighted Capacity Availabilityi = (AMCPh(i) * Capacity Availabilityi) / AMCPavg(m) where: i = the Settlement Interval in month “m”

 MCP , if MCP  0  0, if MCP  0 AMCP =  h(i) = the Trading Hour corresponding to Settlement Interval “i” being calculated avg(m) = the simple average over all Settlement Intervals in month “m” For purposes of such calculation, Capacity Availability for any Settlement Interval shall not exceed the applicable Contract Capacity. (ii)

Using the Price-Weighted Capacity Availability calculated above, the “Price-Weighted Monthly Capacity Availability” for month “m” is calculated as follows: n

Price-Weighted Monthly Capacity Availabilitym = where:

 i

Price-Weighted Capacity Availabilityi

m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” (iii)

Using the Price-Weighted Monthly Capacity Availability calculated above, the “Capacity Price Adjustment Factor” for month “m” is calculated as follows:

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Capacity Price Adjustment Factorm = Price-Weighted Monthly Capacity Availabilitym / (Q * n) where: m = the relevant month within the Delivery Period being calculated Q = the Contract Capacity n = the number of Settlement Intervals in month “m” (iv)

Finally, using the Capacity Price Adjustment Factor calculated above, the “Capacity Payment Reduction” for month “m” is calculated as follows: [Use this formula for CCGTs or Boilers:] Capacity Payment Reductionm,CCGT / BOILER = 0.85 * Monthly Capacity Payment * (1 –Capacity Price Adjustment Factor) [Use this formula for CTs:] Capacity Payment Reductionm,CT = 0.50 * Monthly Capacity Payment * (1 – Capacity Price Adjustment Factor)

(b)

Ancillary Services Capacity Payment Reduction: If, regardless of cause (including by reason of Force Majeure, Forced Outage or Planned Outage), for each Ancillary Service listed in Section F of Appendix 1.4, the A/S Availability of a Generating Unit is less than the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4 in any Settlement Interval of a month, then the A/S Capacity Payment Reduction for the Generating Unit for that month will be calculated as follows: (i)

The “Monthly Available A/S Capacity” for month “m” is calculated as follows: n

Monthly Available A/S Capacitym = where:

 k

i

A/S Availabilityi,k

m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” i = the Settlement Interval in month “m” k = the applicable Ancillary Service For purposes of such calculation, for each Ancillary Service, A/S Availability for any Settlement Interval shall not exceed the applicable A/S Maximum Capacity quantity specified in Section F of Appendix 1.4. (ii)

Using the Monthly Available A/S Capacity calculated above, the “A/S Price Adjustment Factor” for month “m” is calculated as follows: A/S Price Adjustment Factorm = Monthly Available A/S Capacitym /



A/S Maximum Capacityk * n) where: ( k

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A/S Maximum Capacity is set forth in Section F of Appendix 1.4 m = the relevant month within the Delivery Period being calculated n = the number of Settlement Intervals in month “m” k = the applicable Ancillary Service (iii)

Using the A/S Price Adjustment Factor calculated above, the “A/S Capacity Payment Reduction” for month “m” is calculated as follows: [Use this formula for CCGTs or Boilers:] A/S Capacity Payment Reductionm,CCGT/ BOILER = 0.15 * Monthly Capacity Payment * (1 – A/S Price Adjustment Factor) [Use this formula for CTs:] A/S Capacity Payment Reductionm,CT = 0.50 * Monthly Capacity Payment * (1 – A/S Price Adjustment Factor)

(c)

3.3

Reduced Monthly Capacity Payment: The “Reduced Monthly Capacity Payment” shall be equal to (i) the Monthly Capacity Payment less (ii) the sum of [a] the Capacity Payment Reduction and [b] the A/S Capacity Payment Reduction.

Other Events Affecting Availability (a)

If Seller fails to take any action necessary to make the Product (or any portion of the Product) deliverable or otherwise available to SCE at the Energy Delivery Point, including maintenance, repair, or replacement of equipment in Seller’s possession or control that must be used for SCE to take delivery of the Product after, or transmit the Product from, the Energy Delivery Point, or such equipment fails for any reason including by reason of Force Majeure or any Outage, then, to the extent SCE is unable to take delivery of the Product after, or to transmit the Product from, the Energy Delivery Point by reason of such failures by Seller, the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(b)

If Seller fails to take any action within its control that is necessary to deliver the Natural Gas Requirements to the Generating Unit(s), including maintenance, repair or replacement of equipment in Seller’s possession or control that must be used to deliver the Natural Gas Requirements to the Generating Unit(s), or such equipment in Seller’s possession or control fails for any reason, including by reason of Force Majeure or any Outage, then, to the extent the Natural Gas Requirements are unable to be delivered to the Generating Unit(s), the Generating Unit(s) shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above.

(c)

During the Delivery Period, the Generating Unit will be deemed to be unavailable for the quantity of Contract Capacity and A/S Maximum Capacity that is undeliverable by Seller during all Settlement Intervals that natural gas is unavailable due to loss, curtailment, interruption, or imposition of limitations of natural gas quantities not classified as firm under the SoCalGas Transportation Contract. For any Settlement Interval where the Generating Unit is unavailable under this Section 3.3(c), the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above. (d) If the SoCalGas Transportation Contract,) If the IFA, the PGA, or the MSA are not in effect at any time during the Delivery Period, the Generating UnitUnits shall be deemed to be unavailable for the

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Settlement Intervals during which such agreement or agreements are ineffective, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above. (ed) If Seller starts-up or operates any Generating Unit other than (i) pursuant to a Dispatch Notice or (ii) pursuant to a Non-SCE Dispatch, the Generating Unit shall be deemed to be unavailable for the amount of the Contract Capacity and A/S Maximum Capacity that is not available to SCE, and the Monthly Capacity Payment shall be reduced in accordance with Section 3.2 above. ARTICLE 4 FUEL RESPONSIBILITIES 4.1

SCE’s Obligation

SCE shall provide the Day Ahead Gas Quantity to Seller by 6:3000 AM (PPT) on the Gas Trading Day applicable to each calendar day of the Delivery Period and be responsible for costs associated with providing the Required Natural Gas Quantity to the Generating Units solely through the Fuel Payment as set forth in ArticleSection 3.1(ed). SCE shall not be obligated to reimburse Seller for any separate charges assessed to Seller for gas transportation surcharges, fuel retention charges, imbalances, penalties, storage costs, or fuel-related taxes. 4.2

Seller’s Obligation

Seller shall be responsible for managing, nominating, scheduling, balancing, and transporting all of the Natural Gas Requirements needed to operate each Generating Unit. Seller shall also be responsible for all costs of natural gas associated with a Seller’s Initiated Test as set forth in Article 10. ARTICLE 5 COMBINED HEAT AND POWER (“CHP”) PROGRAM PROVISIONS 5.1

CHP Program Procurement and Seller Eligibility

Seller and SCE acknowledge and agree that SCE is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by SCE pursuant to this Confirmation is and shall be deemed to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to SCE that (a) the Generating Facility met the PURPA efficiency requirements (18 Code of Federal Regulations, Part 292, Section 292.205) as of September 2007; (b) as of the Confirmation Effective Date, the Power Rating of the Generating Facility equals [___] MW; and (c) as of the Confirmation Effective Date, the Generating Facility is a [Unit # 2 and Generating Unit # 4, together with the generating units that are subject to the obligations in the Transition PPA, constitute a Qualifying Facility][Exempt Wholesale Generating Facility]. Notwithstanding anything to the contrary set forth in this Agreement, Seller covenants that the Power Rating of the Generating Facility shall always exceed 5 MW.. 5.2

CPUC Approval; FERC Approval (a)

Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use commercially reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party.

(b)

Either Party has the right to terminate this Confirmation on notice, which will be effective five Business Days after such notice is given, if CPUC Approval has not been obtained or waived by SCE in its sole discretion within 365 days after SCE files its request for CPUC Approval and a

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notice of termination is given on or before the 395th day after SCE files the request for CPUC Approval.(b) Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereby, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report. (c) (c) Failure to obtain CPUC Approval in accordance with this Section 5.2(a) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of SCE to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval. (d)

5.3

Failure to obtain FERC Approval in accordance with this Section 5.2(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

Provision of Information

Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement. ARTICLE 6 SCHEDULING COORDINATOR SERVICES 6.1

SCE as Scheduling Coordinator

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall take all actions and execute and deliver to SCE and the CAISO all documents necessary to authorize or designate SCE as Scheduling Coordinator (“SC”) for each of Generating Unit # 2 and Generating Unit # 4 with the CAISO effective as of the beginning of the Delivery Period. Seller shall not be entitled to any payment under this Confirmation until SCE is fully authorized as the SC for theeach such Generating Unit. During the Delivery Period, and after SCE is designated as SC for a Generating Unit, Seller shall not authorize or designate any other party to act as SC, nor shall Seller perform for its own benefit the duties of SC, and Seller shall not revoke SCE’s authorization to act as SC unless agreed to in writing by SCE. SCE shall submit bids and schedules to the CAISO in accordance with the Tariff and, subject to Article 9 below, the Operating Restrictions. Seller shall reasonably cooperate with SCE in performing any actions

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necessary prior to the start of the Delivery Period to allow each of Generating Unit # 2 and Generating Unit # 4 to be (i) dispatched (or otherwise scheduled to operate) for the first day of the Delivery Period and (ii) reported to or scheduled with the CAISO pursuant to the Tariff, either through SLIC or as otherwise required by the CAISO, as being in an outage at the commencement of the Delivery Period. All CAISO costs and revenues (including credits and other payments) associated with a dispatch of the Generating Unit # 2 or Generating Unit # 4 on the first day of the Delivery Period that are received by Seller or their SC on the day prior to the Delivery Period shall be for SCE’s account. 6.2

Notices

Subject to Seller complying with its obligations under this Confirmation, SCE, as SC, shall submit all notices and updates required under the Tariff regarding each Generating Unit’s status to the CAISO. Seller will comply with Article 9 of this Confirmation in providing such notices and updates. 6.3

CAISO Settlements

As SC, SCE shall be responsible for all settlement functions with the CAISO related to the Generating Units. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to the Generating Units, including any invoices or settlement data, in the format reasonably requested by SCE. 6.4

Terminating SCE’s Designation as SC

At least thirty (30) days prior to the expiration of the Delivery Period, the Parties will take all actions necessary to terminate the designation of SCE as SC as of 11:59 p.m. on the final date of the Delivery Period (“SC Replacement Date”). Such actions include the following: (a) Seller shall (i) submit to the CAISO a designation of a new SC to replace SCE effective as of the SC Replacement Date and (ii) cause its newly designated SC to submit a letter to the CAISO accepting the designation; and (b) SCE shall submit a letter to the CAISO resigning as SC effective as of the SC Replacement Date. Seller bears sole responsibility for locating, selecting, and reaching agreement on terms with any replacement SC. 6.5

Duties Related to Resource Adequacy Resources

If a Generating Unit is designated as a Resource Adequacy Resource, the following will apply: (a)

Seller shall take all actions necessary in order to allow SCE to reasonably perform its duties as an SC for a Resource Adequacy Resource, including, but not limited to, providing all information needed for SCE to include the Generating Units on SCE’s Supply Plan; and

(b)

SCE shall use the Resource Adequacy Availability Management (“RAAM”) software to allow Seller to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”), provided, (i) SCE is not required to use or change its utilization of SCE owned or controlled assets or market positions, to allow Seller to utilize the Substitution Rules, (ii) Seller, at its own expense, provides substitute capacity that complies with the Substitution Rules, (iii) Seller provides, as soon as practicable, but no later than 5:00 a.m. PPT the day bids are due in the IFM for the day Seller seeks to substitute capacity for, all information to SCE needed to substitute capacity pursuant to the Substitution Rules, including, but not limited to, the substitution start and end dates, the Resource ID for the substitute unit, a short description of the outage, the outage ID from SLIC application, and the amount of capacity to be substituted, (iv) SCE’s duties to take action under this subsection (b) are solely limited to inserting one (1) substitution request through RAAM per day; and (v) Seller causes, and is responsible for, the SC of the generating unit Seller seeks to substitute with to cooperate with SCE in making a substitute request and SCE is not responsible or liable for any costs, damages, penalties, charges, or liabilities (“Substitution Costs”) associated with such SC’s failure to cooperate or take the proper action; provided, further, if the CAISO develops a tool, application, or other means, for Seller to submit its own substitution request, then SCE shall not be required to take any action under this Section 6.5(b) to allow Seller to utilize the Substitution Rules. In no event shall SCE be responsible or liable for any Substitution Costs associated with Seller’s

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inability to utilize the Substitution Rules or rejection by the CAISO of any substitute capacity for any reason, including, but not limited to, any RAAM software limitations or failures, unless SCE is required to take action and such Substitution Costs or rejection result solely from SCE’s actions. Seller shall provide the information set forth in Section 6.5(b)(iii) through the Outage Management System. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide such information through (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission of such information as soon as practicable. ARTICLE 7 RMR DESIGNATION 7.1

RMR Contract

IfUpon the request or designation by the CAISO designates the Generating Unit as an RMR unit at any time during the Delivery Periodthat any of the Generating Units be an RMR Unit, whether such request or designation is made directly by the CAISO or at the CAISO’s direction through the Scheduling Coordinator, Seller shall enter into an RMR Contract with CAISO under terms and conditions reasonably acceptable to SCE and Seller. Seller shall not otherwise pursue or enter into an RMR Contract without SCE’s consent. If theany Generating Unit is or becomes an RMR Unit during the Delivery Period, then for any dispatch by CAISO under the RMR Contract, the Operating Restrictions under this Confirmation will be subject to and superseded by any operating restrictions set forth in the RMR Contract or in the CAISO Master File for thethose Generating UnitUnits. Nothing in this Confirmation shall be construed to be a limitation on SCE’s right as a Transmission Owner under the Tariff to file with, or petition, to the FERC any objection or comments relating to any such RMR Contract or any actions SCE or CAISO intend to take with respect to any such RMR Contract. Seller represents, warrants, and covenants to SCE that if an RMR Contract for any Generating Unit for a period in which it is subject to the obligations in this Confirmation goes into effect at any time during the Term, no assignment of such RMR Contract to SCE will be required in connection with this Transaction. The Parties agree that neither this Confirmation nor this Transaction shall operate as an assignment of any such RMR Contract from Seller to SCE, and that in no event shall SCE be required to assume the obligations of Seller under any such RMR Contract. 7.2

RMR Settlements

If thea Generating Unit is designated as a CAISO RMR Unit, then no later than thirty (30) days after such designation by CAISO, Seller shall (i) authorize SCE to act as Seller’s representative (“RMR Settlement Coordinator”) to perform all RMR settlement functions for the RMR Units, (ii) authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder, and (iii) irrevocably assign to SCE all rights to receive any and all payments under the RMR Contract for the Delivery Period. Seller shall take all actions and execute and deliver to SCE all documents or contracts necessary, including any confidentiality agreements or other documents required under the RMR Contract, to authorize or designate SCE with the CAISO as its RMR Settlement Coordinator, and authorize the CAISO to communicate with SCE regarding the RMR Contract and any settlements thereunder. During the Delivery Period, Seller shall not authorize or designate any other party to act as RMR Settlement Coordinator, nor shall Seller perform for its own benefit the duties of RMR Settlement Coordinator, and Seller shall not revoke SCE’s authorization to act as RMR Settlement Coordinator unless agreed to by SCE. Upon SCE’s designation as the RMR Settlement Coordinator, SCE will be responsible for all RMR settlement functions in accordance with the Tariff and the RMR Contract, including rendering monthly RMR invoices to CAISO, settling any RMR charges incurred or RMR revenues earned, and resolving any RMR-related issues

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directly with CAISO. Seller shall cooperate with SCE in SCE’s performance of any settlement functions, and Seller shall promptly deliver to SCE all Generating Unit data and any correspondence or communications with CAISO related to the Generating Unitseach of Generating Unit # 2 and Generating Unit # 4 (whether or not such Generating Units are subject to the obligations of this Confirmation at the time such correspondence or communication with the CAISO is received by Seller), including any invoices or settlement data, in the format reasonably requested by SCE. Upon receipt of any invoice from the CAISO for an RMR Unit (“RMR Invoice”), Seller shall promptly deliver such RMR Invoice to SCE. If the RMR Invoice amount is a charge from CAISO to Seller, Seller shall submit an invoice to SCE setting forth the amounts owed under the RMR Invoice, and SCE shall pay such amount to Seller for remission to CAISO within ten (10) Business Days after SCE’s receipt of such invoice. If the RMR Invoice amount is a payment from CAISO to Seller, Seller shall remit the amount of such payment to SCE within ten (10) Business Days after Seller’s receipt of such payment. To secure Seller’s obligations to remit to SCE any payments received under an RMR Contract or pursuant to an RMR Invoice, Seller hereby grants to SCE a present and continuing security interest in, and lien on (and right of setoff against), and assignment of, all revenues and accounts receivable of Seller with respect to the RMR Contract, and any and all proceeds resulting therefrom (collectively, “RMR Revenues”), whether now or hereafter held by, on behalf of, or for the benefit of, SCE, and Seller agrees to take such action as SCE reasonably requires in order to perfect SCE’s first-priority security interest in, and lien on (and right of setoff against) such RMR Revenues. SCE shall be the Secured Party with respect to the RMR Revenues and shall have all the rights and remedies of the Secured Party under the Transition EEI Agreement with respect to those RMR Revenues. 7.3

Disputes of RMR Invoices

The Parties agree that all RMR Invoices are subject to the Tariff and may be adjusted by the CAISO, or disputed by SCE, as RMR Settlement Coordinator, in accordance with the Tariff. The Parties agree that all RMR Invoices are subject to dispute between the Parties in accordance with Article Six of the Transition Master Agreement; provided, that the time limitation for adjustments or disputes of invoices set forth in Section 6.3 of the Transition Master Agreement shall not apply to RMR Invoices. Notwithstanding anything to the contrary contained in Articles Six or Ten of the Transition Master Agreement, the Parties agree that the obligations under this Article 7 with respect to the payment of RMR Invoices, or the adjustment of such RMR Invoices, shall survive the expiration or termination of the Agreementthis Confirmation for a period of one year beyond the time period which CAISO may adjust, modify or change any previously issued invoice, or any charges or revenues set forth on such invoice pursuant to the Tariff. 7.4

Terminating SCE’s Designation as RMR Settlement Coordinator

SCE’s designation as RMR Settlement Coordinator will remain in effect until the last applicable RMR Invoice and the data associated therewith is received by SCE and SCE completes all RMR settlement functions associated with such final RMR Invoice. In no event shall SCE be the RMR Settlement Coordinator for any operating day that is not within the Delivery Period. A new SC or RMR Settlement Coordinator shall not affect SCE’s ability to receive RMR settlement payment for any Generating Unit for any operating day during the Delivery Period when an RMR contract is in effect between Seller and the CAISO for such Generating Unit. ARTICLE 8 CAISO AND DELIVERY DEVIATION CHARGES 8.1

CAISO Costs and Revenues

Except as otherwise set forth in this Confirmation, SCE shall be responsible for CAISO costs and receive all CAISO revenues (including credits and other payments) incurred in connection with providing SC services, including costs and revenues associated with SCE and CAISO dispatches of theany Generating Unit. The procedures and calculation methodologies set forth in this Article 8 regarding CAISO costs and revenues are in respect to each Generating Unit.

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8.2

CAISO Sanctions

If, during the Term, the CAISO implements or has implemented any sanction or penalty related to scheduling, outage reporting, or generator operation, and any such sanctions or penalties are imposed upon the Generating Unit(s) or to SCE as SC due solely to the actions or inactions of Seller, the cost of the sanctions or penalties shall be the Seller’s responsibility. 8.3

Scheduling and Delivery Deviation Charge

Seller shall pay SCE an SDD Charge if during any Settlement Interval the Qualifying Delivered Energy is less than the Performance Tolerance Band Lower Limit for such Settlement Interval. The SDD Charge is calculated as follows: If A < B, then SDD Charge = 0.5 * (B – A) * C where: A = Qualifying Delivered Energy for the Settlement Interval; B = Performance Tolerance Band Lower Limit; and C = SDD Price. Upon CAISO’s implementation of UDP, or any subsequent changes regarding the calculation of UDP, the Parties agree to negotiate in good faith to amend the SDD Charge calculation as necessary to maintain the economic balance of benefits and burdens contemplated under this Section 8.3. 8.4

SDD Administrative Charge

Seller shall pay SCE an SDD Administrative Charge if during any Settlement Interval Delivered Energy (i) exceeds the Performance Tolerance Band Upper Limit or (ii) is less than the Performance Tolerance Band Lower Limit, for such Settlement Interval. The SDD Administrative Charge is calculated as follows: SDD Administrative Charge = Absolute Value (E – D) * F where: D = Delivered Energy for the Settlement Interval; E = Scheduled Energy for the Settlement Interval; and F = SDD Admin Price. 8.5

Allocation of Standard Capacity Product Payments and Charges

Seller agrees that, if the Generating Unit is a Resource Adequacy Resource, then it is subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account. 8.6

Allocation of Charges Related to Generator Replace Tariff Provisions

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If (a) a Generating Unit is designated as a Resource Adequacy Resource and (b) FERC approves or modifies the Tariff whereby, during periods that the Generating Unit is on a Planned Outage, the SC for a Resource Adequacy Resource is required to (i) replace the Generating Unit with a resource that is not a Resource Adequacy Resource or (ii) face the imposition of a charge, cost, sanction and/or penalty for failing to replace that Generating Unit, then Seller is responsible for (x) replacing the Generating Unit with a resource that is not a Resource Adequacy Resource, and (y) any and all charges, costs, sanctions and/or penalties for failing to replace all or a portion of the Generating Unit. Seller agrees that SCE is not required to take any action, or use or change its utilization of its owned or controlled assets or market positions, to allow Seller to replace the Generating Unit with a resource that is not a Resource Adequacy Resource; provided that SCE in its capacity as SC shall remain liable for compliance by it with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 9 AVAILABILITY NOTICES, BIDS, AWARDS AND DISPATCH 9.1

Notice of Availability

With respect to each Operating Day, no later than two (2) Business Days before each Trading Day, Seller shall provide to SCE using an SCE-provided web-based system (“Outage Management System”) an hourly schedule of the Available Capacity (for both Energy and Ancillary Services) that each Generating Unit is expected to have available for each hour of the applicable Operating Day (the “Availability Notice”). Seller must update SCE immediately using the Outage Management System if the Available Capacity of any Generating Unit changes or is likely to change after the Availability Notice has been submitted to SCE. Seller must follow up each such update through the Outage Management System with a telephonic update to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e). Seller shall accommodate SCE’s reasonable requests for changes in the time or form of delivery of the Availability Notices. If an electronic submittal via the Outage Management System is not available, or is not possible for reasons beyond a Party’s control, Seller may provide Availability Notices using the form attached in Appendix 9.1 by (in order of preference) electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission notice of such availability as soon as practicable. 9.2

Dispatch Notices and Operating Restrictions (a)

Dispatch Notices. SCE will have the right to dispatch each Generating Unit or Generating Units, seven (7) days per week and twenty-four (24) hours per day (including Holidays) and (i) at any level between PMin and Contract Capacity, inclusive, and (ii) at any level between Contract Capacity and PMax if instructed by the CAISO by providing Dispatch Notices to Seller electronically, subject to the terms and conditions set forth in this Confirmation. Subject to the Operating Restrictions, each Dispatch Notice will be effective unless and until SCE modifies such Dispatch Notice by providing Seller with an updated Dispatch Notice. If an electronic submittal is not possible for reasons beyond SCE’s control, SCE may provide Dispatch Notices by (in order of preference) electronic mail, facsimile transmission, or telephonically to the Seller personnel designated to receive such communications as listed in the Appendix 9.2(e). Day-Ahead Dispatch Notices, in the absence of an electronic submittal, shall be provided in a form substantially similar to Appendix 9.2(a). In addition to any other requirements set forth in this Confirmation, all Dispatch Notices will be made in accordance with the Tariff.

(b)

Start-Up Notices. If a Dispatch Notice includes a Start-Up, Seller shall notify SCE electronically when the respective Generating Unit has initiated a turbine start and again when that Generating Unit is synchronized and at Minimum Load ready to be dispatched to the applicable dispatch instruction. Seller shall provide an electronic or facsimile copy of a completed Start-Up Notice, in the form attached to this Confirmation in Appendix 9.2(b), to SCE within twenty-four (24) hours of the Start-Up. When a Dispatch Notice requires a Start-Up or shutdown, Seller will be responsible for

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coordinating all required switchyard switching with the respective grid control center, if applicable.

9.3

(c)

Operating Restrictions. The Operating Restrictions associated with the Product are specified in Appendix 1.4. In providing a Dispatch Notice, SCE shall use reasonable efforts to comply with the applicable Operating Restrictions. If SCE submits a Dispatch Notice that does not conform with the Operating Restrictions, then Seller shall immediately notify SCE of the non-conformity and SCE will modify its Dispatch Notice to conform to the applicable Operating Restrictions. Until such time as SCE submits a modified Dispatch Notice, Seller shall operate the applicable Generating Unit and deliver the Product in accordance with the Operating Restrictions.

(d)

Daily Operating Report. Seller shall provide SCE the Daily Operating Report, in the form attached in Appendix 9.2(d), the day immediately after each Operating Day, for all Generating Units.

(e)

Communication Protocols. The Parties shall agree to the communication protocols outlined in Appendix 9.2(e) to facilitate exchange of information between the Parties.

(f)

MSG Transition Notices. If a Dispatch Notice results in an MSG Transition, Seller shall notify SCE electronically of all such MSG Transitions and the configuration of the Generating Units under such MSG Transitions via the Outage Management System. If the Outage Management System is not available, Seller shall submit such notice via electronic mail, facsimile transmission or, if such submissions are not available, then telephonically to the SCE personnel designated to receive such communications as identified in Appendix 9.2(e) followed by an electronic mail or facsimile transmission notice of such availability as soon as practicable. Seller shall provide such notice within twenty-four (24) hours of last MSG Transition resulting from the respective Dispatch Notice.

CAISO Dispatch

Any award or dispatch of a Generating Unit by the CAISO for any reason (whether pursuant to an RMR Contract, must offer obligations, Energy dispatches or otherwise), shall be deemed to be a dispatch by SCE for purposes of this Confirmation. The Energy dispatched shall be for SCE’s benefit hereunder, and SCE shall pay the costs of such CAISO awards and dispatches in accordance with the terms of this Confirmation as if such dispatches were directed by SCE. SCE shall be entitled to receive and retain for its own account any and all CAISO revenues for such awards and dispatches, including any availability payments under an RMR Contract for any Generating Unit. In no event shall a dispatch by the CAISO be considered a Non-SCE Dispatch pursuant to this Confirmation. CAISO dispatches following any Seller Initiated Test pursuant to Section 10.1 shall not obligate SCE for any associated costs incurred in starting any Generating Unit for, or operation during, such testing period. 9.4

Non-SCE Dispatch

During the Delivery Period, Seller shall not start-up or operate any Generating Unit other than (a) pursuant to a Dispatch Notice or (b) pursuant to a Non-SCE Dispatch. Seller shall, to the extent possible, notify SCE no later than 5:00 a.m. PPT at least two (2) Business Days in advance of the Trading Day of any start-up or operation pursuant to a Non-SCE Dispatch, and shall, except as otherwise required by Applicable Law, delay such start-up or operation if requested by SCE. Seller shall indemnify, defend, and hold SCE harmless against the costs or losses of SCE resulting from a Non-SCE Dispatch, including all (i) charges, sanctions, and penalties imposed by CAISO, and (ii) Seller’s Gas Costs incurred pursuant to any such start-up or operation. Imbalance Energy revenues net of any charges, sanctions, and penalties imposed by CAISO for a Non-SCE Dispatch shall be for Seller’s account. ARTICLE 10 TESTING 10.1

Testing

Seller may, at times and for durations reasonably agreed to by SCE, conduct necessary testing of the Generating

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Units. (a) Seller is permitted to conduct such testing during the hours in which Seller receives a Dispatch Notice (“SCE Dispatched Test”). Seller shall not be obligated to pay for the Fuel Payment relating to such SCE Dispatched Test, and SCE shall be responsible for all CAISO costs incurred and receive all revenues during such SCE Dispatched Test in accordance to Section 8.1 of this Confirmation. (b) Subject to Section 10.1(a), if Seller wishes to schedule and conduct a test (“Seller Initiated Test”), SCE shall not be obligated to pay the Fuel Payment to Seller, and Seller shall pay for all costs (including, but not limited to, start-up, fuel and/or transportation costs) relating to and arising out of such Seller Initiated Test in accordance with Section 9.4 of this Confirmation, and SCE shall pay to Seller, in the month following SCE’s receipt of such CAISO revenues, such revenues net of any resource specific charges, penalties, or sanctions associated with the Energy generated and delivered during such Seller Initiated Test. To the extent such Seller Initiated Test prevents SCE from dispatching theany Generating UnitsUnit as it would have absent such test, then, in accordance with the Section 3.2 of this Confirmation, the Generating UnitsUnit will be deemed unavailable. Seller must notify SCE of any Seller Initiated Test no later than 5:00 a.m. PPT at least three (3) Business Days in advance of the Trading Day of any start-up, operation or operational limitation(s) pursuant to the requested test. If Seller Initiated Test is agreed upon by SCE, SCE shall have the option to submit a SelfSchedule in the IFM for the agreed upon testing day for a duration the greater of (i) the number of hours required to complete the test, or (ii) the Minimum Run Time as referenced in Section B of Appendix 1.4. Notwithstanding anything to the contrary in this AgreementConfirmation, such Self-Schedule is not considered a Dispatch Notice. 10.2

SCE Annual Test

At least once per calendar year at SCE’s request, SCE has the right to require Seller to demonstrate, pursuant to the protocols set forth in Appendix 10.2 (the “SCE Annual Test”), each Generating Unit’s ability to provide the Product in accordance with the terms of this Confirmation. In addition, as part of the SCE Annual Test, SCE may inspect the Generating Facility to confirm the configurations of the Generating Unit(s) provided for in Appendix 1.4. The SCE Annual Test shall be at a time mutually agreed to by the Parties. If, during an SCE Annual Test, a Generating Unit fails to demonstrate its ability to provide the Product or any portion thereof (a “Failed Test”), Seller shall, at Seller’s cost and expense, promptly make all necessary repairs to such Generating Unit, and any portion thereof, and/or take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation. The results of any Failed Test will be used to determine the Available Capacity for the applicable Generating Unit, and accordingly, Reduced Monthly Capacity Payments shall apply for such Generating Unit until Seller demonstrates, in accordance with Appendix 10.2, a successful test. Seller agrees that any subsequent test that is performedrequired to demonstrate that Seller has remediedcompliance for a Failed Test shall be a Seller Initiated Test. ARTICLE 11 OUTAGES 11.1

Planned Outages

Upon the later of the Confirmation Effective Date or twenty-four (24) months prior to the beginning ofNo later than 60 days prior to the Delivery Period, and no later than January 1, April 1, July 1, and October 1 of each calendar year thereafter throughout the Term, Seller shall submit to SCE the portion of the Seller’s schedule of proposed Planned Outages (“Outage Schedule”) for the following twenty-four (24) month period that overlaps the Delivery Period via the Outage Management System. If the Outage Management System is not available, Seller shall submit the Outage Schedule in substantially the form set forth in Appendix 11.1. Within twenty (20) Business Days after its receipt of an Outage Schedule, SCE shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Accepted Electrical Practices, accommodate SCE’s

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requests regarding the timing of any Planned Outage. Seller shall cooperate with SCE to arrange and coordinate all Outage Schedules with the CAISO in compliance with all CAISO Outage scheduling and reporting requirements. Seller will communicate to SCE all changes to a Planned Outage including estimated time of return of each Generating Unit as soon as practicable after the condition causing the change becomes known to Seller. 11.2

11.3

Restrictions to Planned Outages (a)

No Planned Outages shall be scheduled or planned from each May 1 through September 30 during the Delivery Period for any Generating Unit subject to this Confirmation, without prior written consent from SCE.

(b)

In the event that the Seller has a Planned Outage for any Generating Unit subject to this Confirmation that becomes coincident with a CAISO-declared system emergency, Seller shall make all reasonable efforts to reschedule such Planned Outage.

Notice of Forced Outages

Seller shall communicate Forced Outages by telephoning SCE’s Generation Operations Center within ten (10) minutes of the commencement of the Forced Outage, at the telephone numbers listed in Appendix 9.2(e). Seller shall utilize SCE’s Outage Management System to enter Outage information as required by the Tariff within twenty (20) minutes of the Forced Outage. If the CAISO imposes a sanction or penalty upon SCE as SC due to Seller’s failure to timely provide SCE with a report of a Forced Outage or Planned Outage for any Generating Unit subject to this Confirmation, Seller shall be responsible for such sanction or penalty. 11.4

Reports of Forced Outages or Planned Outages

Seller shall promptly prepare and provide to SCE, using the Outage Management System or forms, all reports of Forced Outages or Planned Outages for any Generating Unit subject to this Confirmation that SCE may reasonably require for the purpose of enabling SCE to comply with CAISO requirements or any Applicable Laws. Seller shall provide to SCE notice of a Planned Outage no later than seventy-two (72) hours prior to the beginning of any Planned Outage. Seller shall also report all Forced Outages and Planned Outages in the Daily Operating Report. 11.5

Inspection

In the event of a Forced Outage, SCE shall have the right to inspect any Generating Unit and all records relating thereto on any Business Day and at a reasonable time, and Seller shall reasonably cooperate with SCE during any such inspection. ARTICLE 12 METERING, COMMUNICATIONS, AND TELEMETRY 12.1

SCE Access

All communication, metering, telemetry, and associated generation operation equipment will be centralized into each Generating Unit’s Distributed Control System (“DCS”) or Supervisory Control And Data Acquisition system (“SCADA”). Seller shall configure each Generating Unit’s DCS/SCADA so that SCE may access it via the Generation Management System (“GMS”) from SCE’s Generation Operations Center (“GOC”). Seller shall ensure that the access link will provide a monitoring and control interface to enable automatic dispatch of each Generating Unit. Seller shall link the systems via an approved SCE communication network, utilizing existing industry standard network protocol, as approved by SCE. The connection will be bidirectional in nature and used by the Parties to exchange all data points to and from the GOC. SCE and Seller shall each have shared access to information concerning gas data (including data regarding nominations, confirmations, allocations, imbalances,

18

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

and usage) through electronic bulletin boards or remote meter reading devices with respect to all Natural Gas Requirements for each Generating Unit. Seller shall be responsible for the costs of installing, configuring, maintaining and operating the DCS/SCADA and internal site links for each Generating Unit. 12.2

Control Logic

Seller will ensure that each Generating Unit’s DCS/SCADA control logic will be configured to control the Generating Unit in multiple plant configurations as applicable. Each Generating Unit’s control logic will incorporate control signals from multiple locations to perform Energy dispatch, Ancillary Services, and supplemental energy functions. Control logic will perform all coordinated megawatt control and Automatic Generation Control (“AGC”) independently for each Generating Unit. 12.3

Delivery of Data

At least thirty (30) days prior to the beginning of the Delivery Period, Seller shall provide SCE with all facility and metering information necessary to communicate with SCE, including the information set forth in Appendix 12.3. 12.4

Satellite Communication System

Seller is responsible for installing, testing, commissioning, and maintaining the Satellite Communications System (“SCS”) for each Generating Unit in accordance with instructions provided by SCE and the SCS vendor. Seller shall grant SCE reasonable access to the Generating Units during regular business hours for routine calibration and maintenance of the SCS at any time prior to the expiration of the Delivery Period. SCE may, at any time, halt the installation, testing, commissioning, or maintenance of the SCS. SCE shall be responsible for the costs associated with installation, testing, commissioning, and maintenance of the SCS, and will provide the SCS to Seller for installation. ARTICLE 13 OPERATION, MAINTENANCE, AND REPAIR 13.1

Seller’s Operation Obligations During the Delivery Period: (a)

Seller shall operate each Generating Unit in accordance with Accepted Electrical Practices, Applicable Laws, the applicable Permit Requirements, applicable California utility industry standards, including the standards established by the California Electricity Generation Facilities Standards Committee pursuant to Public Utilities Code Section 761.3 and enforced by the CPUC, CPUC General Order 167, and CAISO mandated standards, as set forth in the Tariff (collectively, “Industry Standards”);

(b)

Seller shall maintain a daily operations log for each Generating Unit which shall include information on power production, fuel consumption and efficiency (if applicable), availability, maintenance performed, Outages, changes in operating status, inspections and any other significant events related to the operation of each Generating Unit. In addition, Seller shall maintain all records applicable to each Generating Unit, including the electrical characteristics of the generators and settings or adjustments of the generator control equipment and protective devices. Information maintained pursuant to this Section 13.1 shall be provided to SCE, within five (5) Business Days of SCE's request; and

(c)

Seller shall maintain and make available to SCE and the CPUC, or any division thereof, records, including the plant operations logbooks demonstrating that the Generating Units are operated and maintained in accordance with Industry Standards. Seller shall comply with all reporting requirements and permit on-site audits, investigations, tests, and inspections permitted or required under any Applicable Laws, Permit Requirements, or Industry Standards.

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13.2

Seller’s Maintenance and Repair Obligations During the Delivery Period: (a)

Seller shall inspect, maintain, and repair each Generating Unit, and any portion thereof, in accordance with applicable Industry Standards and Accepted Electrical Practices. Seller shall maintain and deliver to SCE within five (5) Business Days of aupon request, all maintenance and repair records and plant equipment test data of each Generating Unit; provided, however, if Seller must obtain such records and data from a third-party, Seller shall promptly request such records and data from the applicable third-party and shall provide the requested records and data to SCE within five (5) Business Days of receipt.

(b)

In the event that: (i)

an SCE Annual Test demonstrates that the Available Capacity of a Generating Unit is less than or equal to seventy-five percent (75%) of Contract Capacity, or

(ii)

an equipment failure with respect to a Generating Unit results in the Available Capacity of such unit being less than or equal to seventy-five percent (75%) of Contract Capacity on average for a period of time exceeding seven (7) days,

Seller shall repair such Generating Unit in accordance with Accepted Electrical Practices and the procedure set forth in this Article 13. Within fourteen (14) days of any such failure, Seller shall complete a Successful Repair or present to SCE a written report providing a description of the reason for the failure and a plan and schedule for completing a Successful Repair within the time specified in the repair plan (“Repair Plan”). If SCE and Seller disagree about the Repair Plan, SCE may, at its expense, hire an independent third party engineering firm reasonably acceptable to Seller (“IE”), to assess the situation and make recommendations for completing a Successful Repair. Upon SCE providing two (2) Business Days notice by SCE., Seller shall grant the IE and SCE personnel access to the Generating Facility and all relevant operational log books, maintenance records and reports. Seller shall use best efforts to follow the recommendations of the IE’s engineering report for achieving a Successful Repair. Until a Successful Repair is demonstrated, the Generating Unit(s) will be deemed unavailable for purposes of Section 3.2 of this Confirmation; provided, upon Seller’s demonstration of a Successful Repair, the Generating Unit(s) will be deemed available retroactive to the hour that such Successful Repair was initiated; (c)

Subject to Section 13.2(b), Seller shall promptly make all necessary repairs to each Generating Unit, and any portion thereof, and take all actions necessary in order to provide the Product to SCE in accordance with the terms of this Confirmation; and

(d)

Seller shall not allow the Available Capacity of any Generating Unit to fall below seventy-five percent (75%) of Contract Capacity on average for a period of: (i)

six (6) months (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) due to Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such six (6) month period (or longer cure period identified in the IE’s written report); or

(ii)

sixty (60) days (whether or not consecutive) within a rolling twelve (12) month period (or such longer cure period identified as reasonable under the circumstances in the written report of an IE engaged by SCE) for any reason or circumstance, including Forced Outage, but excluding

20

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Planned Outage and Force Majeure if the IE has determined in its written report that Seller should reasonably have been able to achieve a Successful Repair of the Generating Unit(s) prior to the expiration of such sixty (60) day period (or longer cure period identified in the IE’s written report). 13.3

Operational Representations, Warranties, and Covenants by Seller

Seller represents, warrants, and covenants with respect to Sections 13.3(a) through (d) and Seller covenants with respect to Section 13.3(e) to SCE that: (a)

Prior to the start of the Delivery Period, Seller has executed a PGA and MSA; Seller has delivered to SCE a true and complete copy of such PGA and MSA; and such PGA and MSA, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the duration of the Delivery Period; provided that Seller shall be allowed to agree to any amendment or modification to the PGA and/or MSA if FERC approves a new form of such agreements for the CAISO, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10) Business Days of such amendment or modification.

(b)

Prior to the start of the Delivery Period, Seller has executed all necessary grid connection, maintenance, or transmission facility services agreements; Seller has delivered to SCE a true and complete copy of such agreements; and such agreements, as originally executed by Seller, shall remain in full force and effect without amendment or modification throughout the Term; provided that if FERC authorizes the Transmission Owner to amend or modify such agreements with Seller, Seller is authorized to accept any such FERC-approved modified or amendment agreement, and further provided Seller must provide Buyer a copy of such amendment or modification within ten (10) Business Days of such amendment or modification.

(c)

Prior to the start of the Delivery Period, Seller has good and defensible title, or valid and effective leasehold rights in the case of leased property, to each Generating Unit subject to this Confirmation , free and clear of all liens, charges, claims, pledges, security interests, equities, and encumbrances of any nature whatsoever other than (i) the lien of current taxes not delinquent; (ii) liens, charges, claims, pledges, security interests, equities, and encumbrances that in the aggregate are not substantial in amount and do not detract from or interfere with the ability of Seller to deliver the Product; or (iii) liens listed in Appendix 13.3(c) delivered by Seller to SCE prior to the Confirmation Effective Date (the “Disclosure Schedule”);

(bd) On the Confirmation Effective Date, the “Historical Outage Report” sets forth true and accurate historical data of (a) the dates during which each Generating Unit (including the Generating Units that will become subject to the obligations of this Confirmation during the Delivery Period) was available to generate Energy during the period from the beginning of the calendar year two (2) years prior to the Confirmation Effective Date2009 to the present regardless of whether or not such Generating Unit did in fact generate Energy, and each Generating Unit's capacity to generate Energy for each of those dates during which the Generating Unit was available, and (b) for those dates when each Generating Unit was not available to generate Energy, the reasons for such unavailability; and (c)

Noe) In the event SCE is not the SC, no later than two weeks prior to the first day of the Delivery Period, Seller shall take all actions necessary with the CAISO and SCE to ensure that by the day immediately prior to the first day of the Delivery Period, the CAISO Master File and, if applicable, the RMR Contract reflect the values that SCE deems appropriate based on the Operating Restrictions under this Confirmation. If, at any time prior to the termination of this Confirmation, any action or inaction of Seller, or a condition of any Generating Unit that could result in a revision to the CAISO Master File or to the operating restrictions set forth in an RMR Contract, then Seller shall promptly give notice to SCE and shall use all reasonable efforts to maintain the Operating Restrictions exactly as they existed on the Confirmation Effective Date.

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ARTICLE 14 ELECTRIC SYSTEM RELIABILITY STANDARDS During the Delivery Period, Seller shall be (i) responsible for complying with any NERC Reliability Standards applicable to the Generating Units, including registration with NERC as the Generator Operator for the Generating Units or other applicable category under the NERC Reliability Standards and implementation of all applicable processes and procedures required by NERC, WECC or CAISO for compliance with the NERC Reliability Standards; and (ii) liable for all penalties assessed by NERC (through WECC or otherwise) for violations of the NERC Reliability Standards by the Generating Facility or Seller, as Generator Operator or other applicable category. However, if Seller learns that NERC (through WECC or otherwise) is considering or intends to assess Seller with a penalty that Seller believes is attributable to SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the potential assessment, Seller shall provide SCE with sufficient notice to allow SCE to take part in administrative processes, discussions or settlement negotiations with NERC, WECC or other entity arising from or related to the alleged violation or possible penalty. If the penalty is nonetheless assessed in spite of SCE’s participation in the processes, discussions or settlement negotiations, or SCE waives its right to take part in the processes, discussion or settlement negotiations, SCE shall reimburse Seller for the penalty to the extent that (a) it was solely caused by SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the violation; and (b) Seller can establish to SCE’s reasonable satisfaction that the penalty was actually assessed against Seller by NERC and paid by Seller to NERC. If SCE took part in and agreed to the terms of settlement, SCE shall also reimburse Seller for any payment made by Seller in settlement of a claim of violation by or on behalf of NERC, to the extent that (x) the claim being settled was solely caused by SCE’s actions or inactions as SC as described in the document entitled “NERC Reliability Standards - Responsibilities of the Generator Operator, Scheduling Coordinator, CAISO, and Reliability Coordinator” or other successor description or document on the CAISO website at the time of the claim; and (y) Seller can establish to SCE’s reasonable satisfaction that Seller actually made the payment to NERC under the settlement. ARTICLE 15 CREDIT TERMS AND MARK-TO-MARKET VALUE 15.1

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEI Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, if: (i) Seller has’s Exposure to SCE in respect of the Transaction, then the amount of Exposure for this Transaction is deemed to be zero dollars ($0for this Transaction shall be zero dollars ($0) and (ii) SCE’s Exposure to Seller plus the Independent Amount, if any, for this Transaction shall not exceed one million six hundred thousand dollars ($1,600,000) (unless otherwise defined, capitalized terms in this Article 15 are used with the meanings ascribed to them in the Transition Collateral Annex). 15.2

Independent Amount

If Seller’s Credit Rating is lower than BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch, Seller shall have a Full Floating Independent Amount of the amount equal to ten percent (10%) of the market value of this Transaction. Upon the Confirmation Effective Date and until the start of the Delivery Period the term “market value” shall mean the sum of the Monthly Capacity Payments to be paid under this Transaction for the Delivery Period, and upon the start of the Delivery Period the term “market value” shall mean the sum of the Monthly Capacity Payments for the current month and all remaining months of the Delivery Period to be paid under this Transaction. 15.3

Mark-to-Market Value

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

For purposes of determining Exposure for this Transaction, the Parties shall calculate the Current Mark-to-Market Value of this Transaction using the following methodology (unless otherwise defined, capitalized terms in this Section 15.2 are used with the meanings ascribed to them in the Collateral Annex). On any Calculation Date, the Current Mark-to-Market Value for this Transaction will be calculated by taking the sum of the Present Values for each remaining (full or partial) month prior to the termination of this Transaction using the equation below: Current

Mark-to-Market

Value

=

where:

and: Variable n i

Pt,i

Po,i

Gt,i

Description The number of forward months included in the mark-to-market calculation. A forward month. For the balance of the month of the Calculation Date, i=0. For the month following the month of the Calculation Date, i=1, etc. The midpoint from aweighted average of Forward Price AssessmentAssessments for SPNP15 on-peak and off peak power for the relevant forward month i on the Calculation Date for combined cycle technology (for combustion turbine technology, the on-peak price will be multiplied by 1.20 for the relevant forward month i). If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price shall be usedcalculated from the Forward Price Assessments for NP15 on-peak and off-peak power for the last available year. The midpoint from aweighted average of Forward Price AssessmentAssessments for SPNP15 on-peak and off-peak power for the relevant forward month i on the Confirmation Effective Date for combined cycle technology (for combustion turbine technology, the on-peak price will be multiplied by 1.20 for the relevant forward month i). . If no monthly price is available for a Forward Price Assessment, then the applicable monthly Shaped Price shall be usedcalculated from the Forward Price Assessments for NP15 on-peak and off-peak power for the last available year. NYMEX Southern California GasPG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCalPG&E City Gate Basis) for the relevant forward month i on the Calculation Date. If no such gas price is available on the Calculation Date, then a proxy value of NYMEX Southern California Border natural gas plus rate G-BTS1 located in SoCalGas Schedule No. G-BTS (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCal Border Basis plus rate G-BTS1 per MMBtu) for the relevant forward month i shall apply. If neither of the aforementioned gas prices isare available, then

23

Units

$/MWh

$/MWh

$/MMBtu

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Go,i

HRi

Qi c d

the gas price for the relevant calendar month of the last available year shall be used. NYMEX Southern California GasPG&E City Gate natural gas (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCalPG&E City Gate Basis) for the relevant forward month i on the Confirmation Effective Date. If no such gas price is available on the Confirmation Effective Date, then a proxy value of NYMEX Southern California Border natural gas plus rate G-BTS1 located in SoCalGas Schedule No. G-BTS (i.e., closing price for NYMEX Henry Hub plus Henry Hub to SoCal Border Basis plus rate G-BTS1 per MMBtu) for the relevant forward month i shall apply. If neither of the aforementioned gas prices isare available, then the gas price for the relevant calendar month of the last available year shall be used. The Heat Rate associated with the Contract Capacity as specified in Appendix 5.3 of this Confirmation. The Contract Capacity multiplied by the hours remaining under the Transaction for the relevant forward month Interest rate (annualized) Number of compounds per year (e.g. c = 12 if

$/MMBtu

MMBtu/MWh MW * Hours %

= monthly)

Number of days between calculation date ( ) and payment date.

A positive Current Mark to Market Value implies SCE has the potential for realization of market gains and thus has Exposure to Seller’s default or non-performance. Notwithstanding anything to the contrary contained in the Transition Collateral Annex or this Confirmation, the Parties shall determine the Settlement Amount for this Transaction in accordance with Section 5.2 of the Master Agreement. ARTICLE 16 ASSIGNMENT In the event of an Assignment permitted under Section 10.5 of the Transition Master Agreement, (i) any such assignee shall agree in writing to be bound by the terms and conditions hereof, (ii) the Collateral Threshold for such assignee shall automatically be deemed to be zero unless the non-assigning Party otherwise agrees, and (iii) the transferring Party must deliver such tax and enforceability assurance as the non-assigning Party may reasonably request. Any assignment in violation of this Article 16 shall be null and void.

ARTICLE 17 CONFIDENTIALITY In addition to the Parties’ obligations under Section 10.11 of the Transition Master Agreement, with respect to this Transaction, Seller agrees that any data, information, or other material Seller receives from SCE or the CAISO pursuant to or in connection with this Confirmation, including any schedules, bids, awards, dispatches, Dispatch Notices, updated Dispatch Notices, settlement statements, Ancillary Services dispatches or awards, or any other information related to the Product (collectively, "Dispatch Data"), shall be confidential to SCE, and Seller shall use such Dispatch Data or other confidential information or material solely in connection with its performance of its obligations under this Confirmation and for no other purpose. Furthermore, Seller shall not disclose this Dispatch Data or other confidential information to any of its employees, personnel, contractors, agents, or consultants who are engaged wholly or in part in the business of marketing or selling wholesale electrical power or natural gas unless such employees, personnel, contractors, agents, or consultants (a) are directly engaged in performing Seller's obligations under this Confirmation, (b) need to know such information in order to perform Seller's obligations under this Confirmation, (c) are informed of (i) the confidentiality of such Dispatch Data and any information governed by this Article 17 and Section 10.11 of the Transition Master Agreement and (ii) the

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requirements of this Confirmation and the Transition Master Agreement, and (d) are directed to comply with the requirements of this Confirmation and the Transition Master Agreement. Seller agrees that irreparable damage to SCE would occur if Seller were to breach its obligations under this Article 17 and that SCE shall be entitled to all available remedies at law or in equity. ARTICLE 18 PAYMENT, NETTING AND SETOFF Unless otherwise set forth herein, the Parties agree that Sections 5.3, 5.6, and Article Six of the Transition Master Agreement shall apply to this Transaction and that any payment due to or due from either Party to the other Party pursuant to the terms of this Confirmation shall be subject to such provisions. ARTICLE 19 CALIFORNIA AIR RESOURCES BOARD REPORTING REQUIREMENTS During the Term, Seller shall provide such information as SCE deems necessary for SCE to comply with those GHG emissions reporting requirements adopted by the California Air Resources Board (“CARB”), or as Seller is otherwise required to provide by Applicable Law or Governmental Authority. ARTICLE 20 ENVIRONMENTAL CHARGES 20.1

Indemnification

Seller is solely responsible for all Environmental Costs and, other than as provided in Sections 20.2 through 20.4, all GHG Charges, Seller’s Compliance Obligation, and all other costs associated with the implementation and regulation of Greenhouse Gas emissions (whether in accordance with AB 32 or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions implemented and regulated by an authorized Governmental Authority) with respect to the Generating Unit(s) and/or Seller. Seller shall indemnify, defend and hold SCE harmless from and against all liabilities, damages, claims, losses, costs and/or expenses (including, without limitation, attorneys’ fees) incurred by or brought against SCE in connection with such Environmental Costs, GHG Charges, Compliance Obligation, and such other costs. 20.2

Greenhouse Gas Emissions Compliance Cost

Notwithstanding anything to the contrary in Section 20.1, and subject to Seller’s compliance with Section 20.3, in the event that a Governmental Authority imposes any taxes, charges, or fees on the Generating Unit(s) or Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (collectively, “GHG Charges”), Seller shall provide SCE documentation of such GHG Charges within 90 days of Seller incurring the obligation to pay the GHG Charge and such documentation shall establish to SCE’s reasonable satisfaction (all such documentation identified in subsections (a)-(f) below shall be collectively referred to hereinafter as “GHG Documentation”), that: (a)

Seller is actually liable for the GHG Charges during the Delivery Period;

(b)

the Applicable Law imposing the GHG Charge was (i) not in effect or (ii) not scheduled to become effective and applicable to the Generating Unit(s) as of the Confirmation Effective Date;

(c)

the specific amount of the GHG Charges;

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(d)

the GHG Charge was imposed upon Seller by an authorized Governmental Authority in whose jurisdiction the Generating Units are located, or which otherwise has jurisdiction over Seller or the Generating Units;

(e)

Seller has paid the Governmental Authority identified in (d) above the full amount of the GHG Charge for which Seller seeks reimbursement from SCE under this Section 20.2; and

(f)

Seller took all reasonable steps to mitigate the cost or amount of such GHG Charges, including utilizing any GHG Credits or revenues described in Section 20.3(a)(i) below; provided, that the reasonable steps shall not be deemed to require Seller to make capital improvements to the Generating Unit.

SCE shall reimburse Seller for such GHG Charge within forty-five (45) calendar days of SCE’s receipt of the GHG Documentation. In no event shall SCE be responsible for GHG Charges associated with Greenhouse Gas emissions that exceed the GHG Cap or a Non-SCE Dispatch during the Term. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period. 20.3

Greenhouse Gas Emissions Credits (a)

In the event that, during the Term, Seller is: (i)

allocated or issued, or has the right to obtain, at no cost to Seller other than administrative or overhead costs, allowances, credits, or other similar rights to emit Greenhouse Gas in accordance with a cap-and-trade or any other federal, state or local legislation, other than AB 32, implemented by an authorized Governmental Authority (“GHG Credits”) to offset or reduce any Greenhouse Gas emissions, then Seller shall obtain and utilize such allowances or credits to mitigate any GHG Charge at no cost to Buyer;

(ii)

allocated or issued or has the right to obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for a portion of or its entire fleet of generating units (all or some of the generating units owned, managed, or controlled by Seller that are subject to any Greenhouse Gas legislation, regulation, law or other similar governmental action) (“Seller’s Fleet”), then Seller shall utilize a proportional amount of such allowances or credits to mitigate any GHG Charge at no cost to SCE; or

(iii)

allocated or receives revenues, whether specific to the Generating Unit(s) or Seller’s Fleet, associated with any allowance or credit allocated at no cost to Seller other than administrative or overhead costs and associated with Greenhouse Gas emissions, then Seller shall remit any such revenue or, if allocated to Seller’s Fleet, the proportional amount of such revenue, to SCE to mitigate any GHG Charge.

For purposes of Section 20.3(a)(ii) and (a)(iii) above, the proportional amount of allowances, credits, or revenues, as applicable, shall be calculated based on the method, formula or other similar calculation by which the Governmental Authority used to determine the amount of GHG Credits (“GHG Calculation”) attributable to each Generating Unit compared to the sum of all GHG Calculations for all generating units within Seller’s Fleet.

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(b)

In the event (i) Seller is not allocated, issued, or granted the right to otherwise obtain, at no cost to Seller other than administrative or overhead costs, GHG Credits for the Generating Units pursuant to Section 20.3(a) above; (ii) Seller is not allocated or issued sufficient GHG Credits to offset GHG Charges attributable to the Generating Units; or (iii) a liquid market for GHG Credits develops and is available to purchase GHG Credits to offset the GHG Charges, then SCE may, at its option, either: (1) self-supply GHG Credits for the Generating Unit(s); or (2) provide Notice to Seller directing Seller to purchase GHG Credits sufficient to cover the GHG Charges associated with the Generating Unit(s). If SCE elects to direct Seller to purchase GHG Credits, Seller shall purchase the number of GHG Credits set forth in the Notice and SCE shall reimburse Seller for those GHG Credits at the lower of Seller’s cost or the prevailing market price at the time the GHG Credits were obtained. In no event shall either Party purchase GHG Credits from an Affiliate.

(c)

All GHG Credits (i) allocated, issued or granted, at no cost to Seller other than administrative or overhead costs, rights to Seller for the Generating Units or (ii) paid for or utilized by SCE shall be the sole and exclusive property of SCE; and any excess GHG Credits (GHG Credits not utilized by SCE under this Confirmation) or revenues resulting from GHG Credits shall be the sole and exclusive property of SCE and shall be retained by SCE.

For purposes of this Section 20.3, all references to “Seller” shall be deemed to include Seller’s parent company, holding company or other entity to which allowances or credits may be or have been allocated to or given rights to obtain, at no cost to such entity other than administrative or overhead costs, for the Generating Units. Sections 20.2 and 20.3 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for GHG Charges incurred by Seller that are (i) a result of Greenhouse Gases emitted by and attributable to the Generating Unit(s) from an SCE Dispatch during the Delivery Period, and (ii) associated with Seller’s compliance with a cap-and-trade program or any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, other than AB 32, implemented and regulated by an authorized Governmental Authority. Sections 20.4 through 20.8 solely apply in determining the rights and obligations of the Parties with respect to Buyer’s compensation of Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period.

20.4

Compensation for Seller’s Compliance Obligation (a)

(b)

If Seller is not eligible for an exemption and subject to Section 20.5, Buyer shall satisfy its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period, in arrears of the creation of such Compliance Obligation, by: (i)

Providing to Seller the Allowances and/or the Offset Credits that will permit Seller to satisfy the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, as further described in Section 20.4(b);

(ii)

Paying to Seller the GHG Compliance Costs for the Delivery Period, as further described in Section 20.4(c); or

(iii)

Utilizing any combination of the compensation methods described in Sections 20.4(b) and 20.4(c), such that Buyer shall fulfill its obligation to compensate Seller for the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period by providing Allowances, Offset Credits and/or the GHG Compliance Costs.

If Buyer, in its sole discretion, elects to provide Seller with Allowances and/or Offset Credits, then Buyer shall, at any time (or from time to time) after Buyer has received the data for calculating the Required Natural Gas Quantity that allows Buyer to calculate Seller’s compensation for any

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portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period, and pursuant to one or more conveyances of Allowances and/or Offset Credits, convey and deliver to Seller, either electronically or otherwise, such Allowances and/or Offset Credits; provided that: (i)

Buyer must transfer such Allowances and/or Offset Credits in a timely manner so as to permit Seller to satisfy the Compliance Obligation imposed on Seller during the Delivery Period (including, without limitation, Seller’s annual compliance obligation, as described in Section 95855 of the GHG Regulations);

(ii)

Upon each conveyance and delivery of such Allowances and/or Offset Credits by Buyer to Seller, Seller shall take all actions to accept delivery of such Allowances and/or Offset Credits such that the conveyed Allowances and/or Offset Credits shall have transferred from Buyer’s account to Seller’s account in accordance with the GHG Regulations;

(iii)

Buyer may, in its sole discretion, reduce the number of Allowances it delivers to Seller pursuant to this Section 20.4(b) by some or all of the Free Allowances that are deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s) and to the extent not applied to a prior conveyance and delivery of Allowances by Buyer to Seller under this Confirmation;

(iv)

The amount of Offset Credits that Buyer conveys and delivers to Seller throughout the Delivery Period (if any) will not exceed the Quantitative Usage Limit for the total Compliance Obligation imposed on Seller with respect to the Generating Unit(s) during the Delivery Period; and

(v)

No later than three (3) Business Days before Buyer conveys and delivers such Allowances and/or Offset Credits to Seller, and also on each of Transfer Date 1, Transfer Date 2 and Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period), Buyer shall deliver a notice to Seller (the “Transfer Notice”), which Transfer Notice shall inform Seller of: (1)

The number of Allowances and/or Offset Credits that Buyer has conveyed and delivered to Seller pursuant to any previous Transfer Notices, and the time-period during the Delivery Period for which such Allowances and/or Offset Credits applied;

(2)

The number of Allowances and/or Offset Credits that Buyer shall convey and deliver to Seller pursuant to the subject Transfer Notice, and the time-period during the Delivery Period for which such Allowances and/or Offset Credits shall apply;

(3)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Transfer Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(4)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Transfer Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(5)

The date on which Buyer shall convey and deliver such Allowances and/or Offset Credits pursuant to the subject Transfer Notice;

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(c)

(6)

The number of Free Allowances deemed allocated to Seller (if any), as disclosed in the Free Allowance Notice(s), which Buyer shall deduct from Buyer’s compensation of Seller to the extent such Free Allowances have not been applied to a prior conveyance and delivery of Allowances by Buyer to Seller pursuant to a Transfer Notice under this Confirmation; and

(7)

The information set forth in Section 20.4(c)(i) through (vi), if Buyer has determined to compensate Seller in part by paying to Seller the GHG Compliance Costs in accordance with Section 20.4(c).

If Buyer, in its sole discretion, elects to compensate Seller by paying to Seller the GHG Compliance Costs, then Buyer (x) shall deliver a notice to Seller on or before Transfer Date 1, Transfer Date 2 and/or Transfer Date 3 (if Transfer Date 3 occurs during the Delivery Period) (such notice, the “Required Payment Notice”), and (y) may, in its sole discretion, deliver a notice to Seller on or before any Optional Transfer Date (such notice, the “Optional Payment Notice”), which Required Payment Notice and Optional Payment Notice shall inform Seller of: (i)

Buyer’s intent to pay to Seller such GHG Compliances Costs;

(ii)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer has compensated Seller pursuant to any previous Required Payment Notices and Optional Payment Notices, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(iii)

The time-period during the Delivery Period for which Buyer has compensated Seller pursuant to any previous Required Payment Notices or Optional Payment Notices;

(iv)

The total number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice, which number is determined pursuant to subparagraph (ii) of the definition of GHG Compliance Costs;

(v)

The time-period during the Delivery Period for which Buyer shall compensate Seller pursuant to the subject Required Payment Notice or Optional Payment Notice; and

(vi)

The date of the upcoming Auction pursuant to which the Auction Settlement Price necessary to calculate the GHG Compliance Costs will be based.

After (1) Seller receives such Required Payment Notice or Optional Payment Notice, and (2) the Auction Settlement Price necessary to calculate such GHG Compliance Costs is published, Seller shall calculate and include as part of the upcoming single regular monthly invoice to Buyer under this Confirmation (and in no event as an invoice that is separate or distinct from such regular monthly invoice), such GHG Compliance Costs. After Buyer’s receipt of such invoice, Buyer shall pay such GHG Compliance Costs along with all other payments due under such invoice in accordance with Article 6 of the Transition Master Agreement. (d)

Seller shall deliver to Buyer a Free Allowance Notice within twenty (20) calendar days of Seller or the Generating Unit(s) being allocated any Free Allowances (with such allocation being determined in accordance with the requirements of subparagraphs (i) or (iv) of the definition of Free Allowance Notice, as applicable, including, without limitation, the requirement that some or all of an allocation of Free Allowances to Seller’s Affiliates shall, if applicable, be deemed to be allocated to Seller). Notwithstanding anything to the contrary set forth in this Section 20.4, to the extent not previously applied, Buyer shall have the right to apply such Free Allowances or the value thereof (as disclosed in the Free Allowance Notice(s)), as applicable, in order to reduce Buyer’s compensation of Seller pursuant to Section 20.4(b) and/or Section 20.4(c) at any time

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during the Term regardless of when such Free Allowances are allocated (or deemed allocated) to Seller. (e)

20.5

Seller acknowledges and agrees that: (i)

Upon Buyer’s conveyance and delivery of Allowances and/or Offset Credits in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)) or Buyer’s payment to Seller of the GHG Compliance Costs in accordance with Section 20.4(c), or any combination thereof, Buyer shall have fulfilled its obligation under this Confirmation to compensate Seller for the Compliance Obligation deemed imposed on Seller with respect to the Generating Unit(s) during the applicable time-periods set forth in the Transfer Notice(s), Required Payment Notice(s) and/or Optional Payment Notices, and that Buyer is not in any way liable for Seller’s failure to satisfy its Compliance Obligation or otherwise comply with AB 32 or the GHG Regulations; and

(ii)

Title to, and risk of loss, invalidation, cancellation or removal of each Allowance and/or Offset Credit conveyed and delivered to Seller by Buyer (including, without limitation, any such loss, invalidation, cancellation or removal of an Allowance and/or Offset Credit as a result of an action by an authorized Governmental Authority in accordance with the GHG Regulations) transfers from Buyer to Seller upon Buyer’s conveyance and delivery to Seller of each such Allowance and/or Offset Credit in accordance with Section 20.4(b) (regardless of whether or not Seller accepts such conveyance and delivery in a timely manner in accordance with Section 20.4(b)(ii)); provided that, if (1) any Offset Credits transferred by Buyer to Seller are invalidated pursuant to the GHG Regulations after the date of such transfer, (2) Seller has not sold or otherwise transferred such Offset Credits to a third party, other than to the Governmental Authority or other entity authorized to implement the regulatory program on behalf of the Governmental Authority in satisfaction of Seller’s compliance obligation (a “Compliance Transfer”), and (3) except in the case of a Compliance Transfer, Seller demonstrates to Buyer’s reasonable satisfaction that it retains title to such invalidated Offset Credits, then to the extent such Offset Credits or other compliance instruments are still required in order for Seller to satisfy the original compliance obligation for which the Offset Credits were transferred by Buyer to Seller, Buyer shall compensate Seller in accordance with and subject to Sections 20.4 through 20.9 for such invalidated Offset Credits to the extent necessary for Buyer to have satisfied, with respect to such invalidated Offset Credits, its obligation under this Confirmation to compensate Seller for the Compliance Obligation imposed on Seller for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period.

Limitation of Liability

Notwithstanding anything to the contrary in the Agreement, Buyer is not responsible for: (a)

Any Compliance Obligation imposed on Seller or the Generating Unit(s), providing any Allowances and/or Offset Credits, or paying any GHG Compliance Costs, to the extent any or all of the aforementioned are associated with Greenhouse Gas emissions that exceed the GHG Cap, that occur outside of the Delivery Period, and/or that result from a Non-SCE Dispatch;

(b)

Any taxes, fees and/or other charges implemented by and imposed upon Seller or the Generating Unit(s) pursuant to Title 17 of the California Code of Regulations, Section 95200, et. seq. (AB 32 Cost of Implementation Fee Regulation), or any similar taxes, charges and/or fees imposed on the Generating Unit(s) or Seller; or

(c)

Any taxes, fees, charges and/or other costs associated with the implementation and regulation of Greenhouse Gas emissions with respect to any generating unit that is not a Generating Unit.

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20.6

20.7

Greenhouse Gas Compliance Covenants (a)

Seller covenants that (i) from the commencement of the Delivery Period until the end of the Term, it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation, and (ii) throughout the Term, it shall comply with all requirements applicable to Seller and/or the Generating Unit(s) under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation.

(b)

Buyer covenants that (i) from the commencement of the Delivery Period until the end of the Term it shall be registered with the CARB to hold Allowances and Offset Credits as necessary to comply with its obligations under this Confirmation, (ii) throughout the Term, it shall comply with all requirements applicable to Buyer under AB 32 and/or the GHG Regulations with respect to its obligations under this Confirmation, (iii) it shall convey and deliver the Allowances and/or Offset Credits to Seller free from all liens, claims, security interests and defects in title, (iv) each Allowance and/or Offset Credit conveyed and delivered to Seller pursuant to this Confirmation (1) will be, at the time it is conveyed and delivered, validly issued and in force in accordance with the GHG Regulations, and (v) it will havewill have been assigned a Vintage Year (as defined in the GHG Regulations) that allows it to be retired during the applicable Compliance Period in accordance with the GHG Regulations, and (2) may be utilized by Seller for compliance with AB 32 and/or the GHG Regulations then in effect, (v) it will have, at the time conveyed and delivered good and marketable title to each Allowance and/or Offset Credit conveyed and delivered to Seller, and that it will obtain and possess at the time conveyed and delivered, each such Allowance and/or Offset Credit lawfully.

Liquid Market for Allowances

If, at any time before the expiration of the Delivery Period, a liquid market for Allowances develops wherein price quotes for Allowances can be obtained, the Parties agree to work in good faith to amend this Confirmation to include a methodology for calculating the GHG Compliance Costs for this Transaction using such price quotes. 20.8

Suspension, Repeal or Supersedence of AB 32; Change in AB 32

Notwithstanding anything to the contrary in the Agreement, if AB 32 is suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then, as of the effective date of such suspension, repeal or supersedence, Sections 20.4 through 20.8 will no longer be in force or effect on a going forward basis; provided that subject to and in accordance the terms of the Agreement, Buyer shall be liable to Seller for compensating Seller for Seller’s Compliance Obligation, if any, imposed on Seller for the Generating Unit(s) before such suspension, repeal or supersedence. To the extent Buyer has provided compensation to Seller pursuant to Sections 20.4(b) and 20.4(c) to cover an expected Compliance Obligation under AB 32 and that obligation is subsequently suspended or repealed, or superseded by any other federal, state or local legislation to offset or reduce any Greenhouse Gas emissions, then Seller shall return any such compensation in a timely manner to Buyer. If a Change in AB 32 occurs, then either Party, on notice, may request the other Party to enter into negotiations to make the minimum changes to this Confirmation necessary to preserve to the maximum extent possible the balance of benefits, burdens and obligations set forth in this Confirmation as of the Confirmation Effective Date. Upon receipt of a notice requesting negotiations, the Parties shall negotiate in good faith. If the Parties are unable, within sixty (60) days after the sending of the notice requesting negotiations, either to agree upon changes to this Confirmation or to resolve issues relating to changes to this Confirmation, then either Party may submit issues pertaining to changes to this Confirmation to dispute resolution as provided in Section 10.6 of the Transition Master Agreement.

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In addition to any notices provided above, Seller shall provide notice to SCE as soon as practicable in the event that Seller believes a Change in AB 32 has occurred. 20.9

Exposure Calculation (a)

Subject to any restrictions set forth in the Agreement (including, without limitation, Section 15.1 and Section 20.5 of this Confirmation), the Parties agree that for purposes of calculating Seller’s Exposure to Buyer in respect of a Transaction under the Confirmation, such calculation shall include Buyer’s obligation to compensate Seller for the Compliance Obligation imposed on Seller for the Generating Unit(s) during the Delivery Period to the extent that such obligation is owed or otherwise accrued and payable (regardless of whether such amounts have been or could be invoiced) to Seller and remains unpaid as of the Calculation Date.

(b)

Seller’s Exposure to Buyer in respect of a Transaction under this Confirmation shall be calculated by multiplying (i) the most recent published ICE OTC Physical Environmental Settlements CCA Index Price for the appropriate vintage (e.g., Dec 2013, Dec 2014) immediately preceding the Calculation Date by (ii) the number of metric tons of Greenhouse Gas emitted by and attributable to the Generating Unit(s) for which Buyer has not compensated Seller pursuant to the Confirmation, with such number to be determined in accordance with subparagraph (ii) of the definition of GHG Compliance Costs (rounded up to the nearest metric ton) set forth in the Confirmation.

ACKNOWLEDGED AND AGREED TO AS OF [________________], 2011: [Seller] OCTOBER 15, 2012: Sycamore Cogeneration Company

Southern California Edison Company

By:

By:

Name:

Name:

Title: Neil Burgess

Title: Name: Marc L. Ulrich

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

Date:

Date:

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APPENDIX A DEFINITIONS UNLESS OTHERWISE DEFINED IN THE TRANSITION MASTER AGREEMENT AND ATTACHMENTS, CAPITALIZED TERMS SHALL BE USED WITH THE MEANINGS ASCRIBED TO THEM IN THE TARIFF. AB 32: The California Global Warming Act of 2006, Assembly Bill 32 (2006) and the regulations promulgated thereunder (including, without limitation, the GHG Regulations) by any authorized Governmental Authority. Accepted Electrical Practices: Those practices, methods, applicable codes, and acts engaged in or approved by a significant portion of the electric power industry during the relevant time period, or any of the practices, methods, and acts which, in exercise of reasonable judgment in light of the facts known at the time a decision is made, could have been expected to accomplish a desired result at reasonable cost consistent with good business practices, reliability, safety, and expedition. Accepted Electrical Practices are not intended to be limited to the optimum practices, methods, or acts to the exclusion of other, but rather to those practices, methods, and acts generally accepted, or approved by a significant portion of the electric power industry in the relevant region, during the relevant time period, as described in the immediately preceding sentence. Adjustment Gas Cost: As set forth in Section 3.1(ed)(viii) of this Confirmation. Adjustment Gas Quantity: As set forth in Section 3.1(ed)(v) of this Confirmation. ADS: The Automatic Dispatch System, or its successor. Air Pollution Control District: A district as defined by Section 39025 of the California Health and Safety Code, Division 26, Air Resources. Allowance: (i) CA GHG Allowance, as such term is defined in the GHG Regulations, or (ii) an allowance specified in Section 95942(b) of the GHG Regulations and approved by the CARB pursuant to Section 95941 of the GHG Regulations. Ancillary Services: As set forth in the Tariff. Ancillary Services Capacity: For each applicable Ancillary Service, the Ancillary Service available to SCE within the scope of operations allowed SCE under this Confirmation pursuant to Section F of Appendix 1.4, plus any other interconnected operation services that the CAISO develops or deems as Ancillary Services. Applicable Laws: Means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Authority having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. A/S Availability: The amount of Ancillary Services Capacity available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. A/S Maximum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the maximum capacity for a particular region in which such Ancillary Service is available. A/S Minimum Capacity: As set forth in Section F of Appendix 1.4 for each applicable Ancillary Service, the minimum capacity for a particular region in which such Ancillary Service is available.

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Auction: Each auction for Allowances conducted in accordance with Subarticle 10 of the GHG Regulations, except for the first auction identified in Section 95910(a)(1) of the GHG Regulations. Auction Settlement Price: As set forth in the GHG Regulations. Automatic Generation Control or AGC: output.

The remote signal control of a Generating Unit’s megawatt

Availability Incentive Payments: As set forth in the Tariff. Availability Notice: As set forth in Section 9.1 of this Confirmation. Availability Standards: As set forth in the Tariff. Available Capacity: The amount of Contract Capacity that is available to SCE under this Confirmation from a Generating Unit during any Settlement Interval. If a Generating Unit’s Available Capacity during any Settlement Interval is below PMin, then the Available Capacity shall be deemed zero for such Settlement Interval. Black Start: As set forth in the Tariff. Boiler or Boiler Unit: Conventional steam cycle. CAISO: The California Independent System Operator or any successor entity performing the same functions. CAISO Grid: The system of transmission lines and associated facilities of the Participating Transmission Owners that have been placed under the CAISO’s operational control. Capacity: Exclusive of any Resource Adequacy Benefits, the maximum dependable operating capability of any generating resource to produce or generate Energy and any other products that may be developed or evolve from time to time that relate to the capability of a generating resource to produce or generate Energy. Capacity Availability: For each Settlement Interval (i) the Generating Unit’s Available Capacity, if the Generating Unit operates within the Performance Tolerance Band, or (ii) the Generating Unit’s Available Capacity, less the product of (x) the difference between (a) Scheduled Energy minus (b) Qualifying Delivered Energy, and (y) the number of Settlement Intervals in one hour, if the Generating Unit operates below the Performance Tolerance Band Lower Limit. In no event shall the Capacity Availability be less than zero MW nor greater than the Contract Capacity for the Generating Unit. CARB: California Air Resources Board, or any successor entity. CCGT: Combined cycle gas turbine. Change in AB 32: A change in AB 32 after the Confirmation Effective Date, which change has a material impact on either party with respect to a Compliance Obligation under Article 20 with respect to the electric energy produced, sold or purchased pursuant to this Confirmation. A Change in AB 32 may include, for example, a change in exemptions or the calculation of compliance obligations, but will not include an increase or decrease in the cost of Allowances or Offset Credits. CHP: As set forth in Article 5 of this Confirmation. Compliance Obligation: As set forth in the GHG Regulations.

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Compliance Period: As set forth in the GHG Regulations. Compliance Transfer: As set forth in Section 20.4(e)(ii) of this Confirmation. Contract Capacity: As set forth in Section A of Appendix 1.4 of this Confirmation, the Quantity of Capacity that Seller is committing to provide to SCE pursuant to this Confirmation. Contract Year: The twelve (12) months within each calendar year from the Confirmation Effective datestarting with the beginning of the Delivery Period until the termination of this Confirmation. CPUC: The California Public Utilities Commission or any successor thereto. CPUC Approval: Either (1)Means a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, or (2) a final and non-appealable disposition of the CPUC’s Energy Division, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation and the, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA in their respective entirety, including payments to be made by SCEBuyer, subject to CPUC review of SCEBuyer’s administration of each of this Confirmation and the, the Transition Master Agreement, the Transition RA Confirmation, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and nonappealable. Crossing Time: Forbidden Region Crossing Time, as set forth in the “Definition” tab of the CAISO Master File. CT: Combustion turbine. Day-Ahead Gas Cost: As set forth in Section 3.1(ed)(vii) of this Confirmation. Day-Ahead Gas Quantity: As set forth in Section 3.1(ed)(iv) of this Confirmation. Delivered Energy: With respect to a Generating Unit and during the Delivery Period, the amount of Energy generated by such Generating Unit and delivered during each Settlement Interval at the Energy Delivery Point as measured by the Energy Metering Equipment, and subject to adjustments identified in this Confirmation. The Delivered Energy in any hour is equal to the sum of the Delivered Energy for each Settlement Interval during such hour. Delivery Period: The period of time commencing on and including the earliest date set forth in the column entitled “Contract Year Start Date” in Appendix 3.1(a), and ending on and including the latest date set forth in the column entitled “Contract Year End Date” in Appendix 3.1(a).Has the meaning specified in Section 1.4 of this Confirmation. Delivery Period End Date: Has the meaning specified in Section 1.4 of this Confirmation. Disclosure Schedule: As set forth in Section 13.3(c) of this Confirmation. Dispatch Data: As set forth in Article 17 of this Confirmation. Dispatch Notice: The operating instruction, and any subsequent updates given by SCE to Seller, directing the applicable Generating Unit to operate at a specified megawatt output or a dispatch given by the CAISO under Section 9.3. Dispatch Notices may be communicated electronically (i.e., through ADS), via e-mail, via facsimile, telephonically, or by other verbal means. Telephonic or other verbal communications shall be documented (either recorded by tape, electronically or in writing) and such recordings shall be made available to both SCE and Seller upon request for settlement purposes.

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Distributed Control System or DCS: The integrated automation system for monitoring and controlling the critical operation functions of a facility that performs tasks essential to the generation of electricity. Emission Reduction Credits or ERC(s): Emission reductions that have been authorized by a local air pollution control district pursuant to California Division 26 Air Resources; Health and Safety Code Sections 40709 and 40709.5, whereby a district has established a system by which all reductions in the emission of air contaminants that are to be used to offset certain future increases in the emission of air contaminants shall be banked prior to use to offset future increases in emissions. Energy: All electrical energy produced, flowing, or supplied by a Generating Unit less the Station Use, measured in kilowatt-hours or multiples units thereof. Energy shall include without limitation any energy associated with Capacity, Ancillary Services, and any other electrical energy product that may be developed or evolve from time to time during the Term. Energy Delivery Point: The point on the CAISO grid defined in Appendix 1.6 of this Confirmation. Energy Metering Equipment: For each Generating Unit, the meters and measuring equipment certified by the CAISO for such Generating Unit, and which measures the Delivered Energy of such Generating Unit. Environmental Costs: Costs incurred in connection with acquiring and maintaining all environmental permits and licenses for the Generating UnitUnits, and the Generating Unit’s compliance with all applicable environmental laws, rules and regulations, including capital costs for pollution mitigation or installation of emissions control equipment required to permit or license the Generating UnitUnits, all operating and maintenance costs for operation of pollution mitigation or control equipment, costs of permit maintenance fees and emission fees as applicable, and the costs of all Emission Reduction Credits or Marketable Emission Trading Credits required by any applicable environmental laws, rules, regulations, and permits to operate, and costs associated with the disposal and clean-up of hazardous substances introduced to the Generating Unit site, and the decontamination or remediation, on or off the Generating Unit site, necessitated by the introduction of such hazardous substances on the Generating Unit site. Envoy: SoCalGas’ internet based electronic bulletin board (called “Envoy”) that monitors electronic gas transactions and serves as SoCalGas’ information management computer system. Exempt Wholesale Generator: An unregulated power generator that is allowed to sell wholesale power as an independent energy producer, and is exempt from the Public Utility Holding Company Act of 1935. Exposure: As set forth in the Transition Collateral Annex. Failed Test: As set forth in Section 10.2 of this Confirmation. FERC Approval: Means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at marketbased rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. Final Test Plan: As set forth in Appendix 10.2 of this Confirmation. Forbidden Operating Region: As set forth in the Tariff.

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Forced Outage: As set forth in the Tariff. Free Allowance: Authority.

Any Allowance freely allocated by the CARB or another authorized Governmental

Free Allowance Notice: The notice delivered by Seller to Buyer in accordance with Section 20.4(d), which notice shall set forth: (i) The aggregate quantity of Free Allowances allocated by the CARB (and/or any other Governmental Authority) to Seller, any of Seller’s Affiliates, and/or the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof); and (ii) Any documentation from the CARB (and/or any other Governmental Authority) relating to such allocation. If the CARB (and/or any other Governmental Authority) allocates Free Allowances to Seller (and/or any of Seller’s Affiliates), but does not specifically allocate such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), then the notice described in this definition shall set forth: (iii) The aggregate quantity of Free Allowances allocated to Seller and/or any of Seller’s Affiliates by the CARB (and/or any other Governmental Authority), and all documentation from the CARB (and/or any other Governmental Authority) relating to such allocation; (iv) The number of Free Allowances that shall be deemed allocated to Seller and/or the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof), which number Seller shall calculate: (1) By utilizing the then-effective methodology established by the CARB (and/or any other Governmental Authority) relating to such allocation, including, without limitation, any methodology that would apportion a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, Covered Entities and/or Opt-in Covered Entities (as each term is defined in the GHG Regulations)) that could be allocated such Free Allowances; or (2) If the CARB (and/or other Governmental Authority) has not established such a methodology, by apportioning a proportionate amount of such Free Allowances to the Generating Unit(s) for Greenhouse Gas emitted by and attributable to the Generating Unit(s) during the Delivery Period (or any portion thereof) as compared to all of the generating units in Seller’s (and/or Seller’s Affiliates’) fleet of generating units and/or other facilities (including, without limitation, oil refineries and/or other industrial process plants) that could be allocated such Free Allowances; and (v) All documentation reasonably necessary to support the methodology set forth in subparagraph (iv)(1) and/or (iv)(2) of this definition, which shall include, without limitation, any documentation reasonably requested by Buyer to verify Seller's methodology and calculations after Buyer’s receipt of such notice. Fuel Payment: As set forth in Section 3.1(e)d) of this Confirmation. Full Floating Independent Amount: As set forth in Section 15.2 of this Confirmation. Full Load: As set forth in Appendix 10.2 of this Confirmation.

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GADS: The Generating Availability Data System, or its successor. Gas Commodity Costs: As set forth in Section 3.1(ed)(vi) of this Confirmation. Gas Day: As defined in the applicable tariff of the gas transporter supplying the Generating Unit. Gas Index: As defined in Section 3.1(ed)(i) of this Confirmation. Gas Trading Day: As set forth in Section 3.1(d)(ii) of this Confirmation. Generating Facility: Power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. The Generating Facility shall include the Generating Units. Generating Unit: The generating unit or units specified in Appendix 1.8 of this Confirmation. References to Generating Units shall be applicable only to Generating Unit # 2 and Generating Unit #4 throughout the Delivery Period. Generating Unit # 2: The Generating Unit described in Section 1.a. of Appendix 1.8 of this Confirmation. Generating Unit # 4: The Generating Unit described in Section 1.b. of Appendix 1.8 of this Confirmation. Generation Operations Center or GOC: The location of SCE’s Real Time operations personnel. Generation Management System or GMS: The automated system employed by SCE real time operations to remotely monitor, dispatch, and control each Generating Unit. Generator Operator: The entity that operates generating unitthe Generating Unit(s) and performs the functions of supplying energy and interconnected operations services as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. Generator Owner: The entity that owns and maintains generating unitsthe Generating Unit(s) as described in NERC's Statement of Compliance Registry Criteria located on the NERC website. GHG Calculation: As set forth in Section 20.3 of this Confirmation. GHG Cap: The GHG Rate times the Required Natural Gas Quantity associated with a Dispatch Notice. GHG Charges: As set forth in Section 20.2 of this Confirmation. GHG Compliance Cost: The dollar amount calculated by multiplying: (i) The cost of one Allowance, determined using the published Auction Settlement Price from the last Auction to have taken place before the date that Buyer’s payment is due to Seller in accordance with Section 20.4(c); by (ii) The number of metric tons of Greenhouse Gas (rounded up to the nearest metric ton) emitted by the Generating Unit(s) during the applicable time-period, which number is determined by multiplying the GHG Rate by the Required Natural Gas Quantity for each calendar day during the applicable time-period; provided that if Buyer determines to compensate Seller for a portion of the Compliance Obligation imposed on Seller with respect to the Generating Unit(s) by providing Seller with Allowances and/or Offset Credits in accordance with Section 20.4(b), the factor set forth in this subparagraph (ii) will be reduced by the number of metric tons of Greenhouse Gas emissions (rounded up to the nearest metric ton) for which Buyer provides such Allowances and/or Offset Credits.

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GHG Credits: As set forth in Section 20.3(a)(i) of this Confirmation. GHG Documentation: As set forth in Section 20.2 of this Confirmation. GHG Rate: The rate for pounds of Greenhouse Gas emissions per MMBtu of natural gas, 117 lbs of Greenhouse Gas emissions /MMBtu, as derived through information provided in the Energy Information Administration’s Documentation for Emissions of Greenhouse Gases in the United States 2005 (DOE/EIA-0638) http://www.eia.doe.gov/oiaf/1605/ggrpt/documentation/pdf/0638(2005).pdfhttp://www.eia.doe.gov/oiaf/160 5/ggrpt/documentation/pdf/0638(2005).pdf and the Environmental Protection Agency’s Emission Factors, AP 42, Fifth Edition, Volume I http://www.epa.gov/ttn/chief/ap42/index.htmlhttp://www.epa.gov/ttn/chief/ap42/index.html. GHG Regulations: Subchapter 10 Climate Change, Article 5, Sections 95800 to 96022, Title 17, California Code of Regulations, as amended or supplemented from time to time. Governmental Authority: Any federal, state, local, municipal, or other governmental, executive, administrative, judicial, or regulatory entity, and the CAISO or any other transmission authority, having or asserting jurisdiction over a Party, any Generating Unit or this Confirmation. Green Attributes: Any and all credits, benefits, emissions reductions, offsets, and allowances, howsoever entitled, attributable to the generation from the Project, and its avoided emission of pollutants. Green Attributes include but are not limited to Renewable Energy Credits, as well as: (1)

Any avoided emission of pollutants to the air, soil or water such as sulfur oxides (SOx), nitrogen oxides (NOx), carbon monoxide (CO) and other pollutants;

(2)

Any avoided emissions of carbon dioxide (CO2), methane (CH4), nitrous oxide, hydrofluorocarbons, perfluorocarbons, sulfur hexafluoride and other greenhouse gases (GHGs) that have been determined by the United Nations Intergovernmental Panel on Climate Change, or otherwise by law, to contribute to the actual or potential threat of altering the Earth’s climate by trapping heat in the atmosphere;1

(3)

The reporting rights to these avoided emissions, such as Green Tag Reporting Rights.

Green Tag Reporting Rights are the right of a Green Tag Purchaser to report the ownership of accumulated Green Tags in compliance with federal or state law, if applicable, and to a federal or state agency or any other party at the Green Tag Purchaser’s discretion, and include without limitation those Green Tag Reporting Rights accruing under Section 1605(b) of The Energy Policy Act of 1992 and any present or future federal, state, or local law, regulation or bill, and international or foreign emissions trading program. Green Tags are accumulated on a MWh basis and one Green Tag represents the Green Attributes associated with one (1) MWh of energy. Green Attributes do not include: (i)

Any energy, capacity, reliability or other power attributes from the Project,

(ii)

Production tax credits associated with the construction or operation of the Project and other financial incentives in the form of credits, reductions, or allowances associated with the Project that are applicable to a state or federal income taxation obligation,

1

Avoided emissions may or may not have any value for GHG compliance purposes. Although avoided emissions are included in the list of Green Attributes, this inclusion does not create any right to use those avoided emissions to comply with any GHG regulatory program.

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

(iii)

Fuel-related subsidies or “tipping fees” that may be paid to Seller to accept certain fuels, or local subsidies received by the generator for the destruction of particular preexisting pollutants or the promotion of local environmental benefits, or

(iv)

Emission reduction credits encumbered or used by the Project for compliance with local, state, or federal operating and/or air quality permits.

If the Project is a biomass or biogas facility and Seller receives any tradable Green Attributes based on the greenhouse gas reduction benefits or other emission offsets attributed to its fuel usage, it shall provide Buyer with sufficient Green Attributes to ensure that there are zero net emissions associated with the production of electricity from the Project. Greenhouse Gas: As set forth in the GHG Regulations. Heat Rate: The amount of natural gas in MMBtu required to produce one MWh of Energy. Historical Outage Report: As set forth in Section 13.3(bd) of this Confirmation. Holiday: New Year’s Day, Presidents’ Day, Memorial Day, Independence Day, Labor Day, Veterans Day, Thanksgiving Day, or Christmas Day. When any Holiday falls on a Sunday, the following Monday will be recognized as a Holiday. No change will be made for Holidays falling on Saturday. Host Site: The site at which the Site Host Load is consumed, including real property, facilities and equipment owned or operated by the Site Host or its Affiliates located at such site. IE: As set forth in Section 13.2(b) of this Confirmation. IFA or Interconnection Facilities Agreement: Any agreement between the Seller and its Participating Transmission Owner providing for the transmission of electrical energy from the Generating Unit to the Pointpoint of Interconnectioninterconnection. IFM or Integrated Forward Market: As set forth in the Tariff. Industry Standards: As set forth in Section 13.1 of this Confirmation. Lower MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Marketable Emission Trading Credits: Without limitation, emissions trading credits or units pursuant to the requirements of California Division 26 Air Resources; Health & Safety Code Section 39616 and Section 40440.2 for market based incentive programs such as the South Coast Air Quality Management District’s Regional Clean Air Incentives Market, also known as RECLAIM, and allowances of sulfur dioxide trading credits as required under Title IV of the Federal Clean Air Act (see 42 U.S.C. § 7651b.(a) to (f)). Master File: As set forth in the Tariff. Maximum Daily Start-Ups: As set forth in the Tariff. MCP or Market Clearing Price: For each Settlement Interval, the Day-Ahead Market price for the hour in which such Settlement Interval falls for the SP15 EZ Gen Hub. Minimum Down Time: As set forth in the Tariff. Minimum Load: As set forth in the Tariff.

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Minimum Run Time: As set forth in the Tariff. Monthly Capacity Payment: As set forth in Appendix 3.1(a), but subject to Article 3 of this Confirmation. MSA or Meter Service Agreement: Scheduling Coordinator Meter Service Agreement. MSG Transition: As set forth in FERC filing ER10-1360 or as modified and approved by FERC thereafter to be incorporated in the Tariff or otherwise applicable to CAISO. Natural Gas Requirements: All of the Generating UnitsUnit’s natural gas requirements, including the Required Natural Gas Quantity, natural gas for any Non- SCE Dispatch and natural gas for any other purpose. NERC/GADS Protocols: The GADS protocols established by NERC, as may be updated from time to time. NERC Holidays: “Additional Off-peak Days” as defined by NERC on the NERC website at http://www.nerc.comhttp://www.nerc.com. NERC Reliability Standards: Those reliability standards applicable to the Generating Facility, or to the Generator Owner or the Generator Operator with respect to the Generating Facility, that are adopted by NERC and approved by the applicable regulatory authorities and and available on the NERC website. Non-Availability Charges: As set forth in the Tariff. Non-SCE Dispatch: A dispatch by Seller either (a) pursuant to a Seller Initiated Test or (b) as required by Applicable Laws. Non-Spinning Reserve: As set forth in the Tariff. Offset Credit: As set forth in the GHG Regulations. Operating Day: A day within the Delivery Period on which the Generating Unit operates. Operating Level: As set forth in the “Definition” tab of the CAISO Master File. Operating Reserve Ramp Rate: As set forth in the Tariff. Operating Restriction: Limitations on SCE’s ability to schedule and use Capacity, Ancillary Services, and Energy for each Generating Unit subject to this Confirmation that are identified in Appendix 1.4. Operational Ramp Rate: As set forth in the Tariff. Optional Payment Notice: As set forth in Section 20.4(c). Optional Transfer Date: The first (1st) Business Day of the month in which an Auction during the Delivery Period takes place, not including Transfer Date 2 or Transfer Date 3. Outage: As set for in the Tariff. Outage Management System: As set forth in Section 9.1 of this Confirmation. Outage Schedule: As set forth in Section 11.1 of this Confirmation. Pacific Prevailing Time or PPT: Pacific Daylight Time when California observes Daylight Savings Time

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and Pacific Standard Time otherwise. Participating Transmission Owner: A transmission owner which has released operational control of its transmission facilities to the CAISO. Performance Tolerance Band: The higher of (a) three percent (3%) of a Generating Unit’s PMax divided by the number of Settlement Intervals in an hour, (b) five (5) MW divided by the number of Settlement Intervals in an hour, or (c) the applicable Regulation Award divided by the number of Settlement Intervals in an hour. If, at any time, the CAISO implements changes to the Performance Tolerance Band, then the Parties agree to negotiate in good faith to amend this definition to maintain the economic benefits and burdens contemplated under this Confirmation. Performance Tolerance Band Lower Limit: A quantity of Energy determined for a Settlement Interval equal to Scheduled Energy minus the Performance Tolerance Band. Performance Tolerance Band Upper Limit: A quantity determined for a Settlement Interval equal to Scheduled Energy plus the Performance Tolerance Band. Permit Requirements: Any requirement or limitation imposed as a condition of a permit or other authorization relating to construction or operation of the Generating Units subject to the obligations of this Confirmation or related facilities, including limitations on any pollutant emissions levels, limitations on fuel combustion or heat input throughput, limitations on operational levels or operational time, limitations on any specified operating constraint, requirements for acquisition and provision of any Emission Reduction Credits or Marketable Emission Trading Credits; or any other operational restriction or specification related to compliance with any Applicable Laws. PGA or Participating Generator Agreement: As set forth in the Tariff. Planned Outage: As set forth in the applicable CPUC Decisions, namely a planned, scheduled, or any other Outage for the routine repair or maintenance of the UnitGenerating Units, or for the purposes of new construction work, and does not include any Outage designated as either forced or unplanned as defined by the CAISO or NERC/GADS Protocols. PMax: As defined in the Tariff. The value of PMax is specified in Appendix 1.4 of this Confirmation. PMin: Minimum Load. Power Rating: The electrical power output value indicated on the generating equipment nameplate. Present Value: The value on a given date of a future payment or series of future payments, discounted using the appropriate yield curve based on the U.S. Treasury constant maturities securities as posted by the Federal Reserve in their H.15 daily update at the following address: http://www.ustreas.gov/offices/domestic-finance/debt-management/interest-rate/yield.html. Product: As set forth in Section 1.5 of this Confirmation. Project: The Generating Facility. Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Protective Apparatus: The control devices (such as meters, relays, power circuit breakers and synchronizers) specified in the Interconnection Facilities Agreement for the Generating Unit.

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PTC 22: The performance test code entitled “PTC-22-2005 - Gas Turbines," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PTC 46: The performance test code entitled “PTC 46-1996 - Overall Plant Performance," as published by the American Society of Mechanical Engineers, which provides standards and directions for conducting and reporting tests, of which code(s) or as may be revised from time-to-time. PURPA: The Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. Qualifying Delivered Energy: The lesser of Delivered Energy or the Performance Tolerance Band Upper Limit for each Settlement Interval during the Delivery Period. Qualifying Delivered Energy shall be zero (0) (i) during a Seller Initiated Test; (ii) during a Non-SCE Dispatch; (iii) if the Delivered Energy is less than PMin minus the Performance Tolerance Band; or (iv) during a Start-Up. Qualifying Facility: An electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of self-certification pursuant to 18 CFR Part 292.207(a). Quantitative Usage Limit: As set forth in the GHG Regulations. RA Confirmation: That certain Resource Adequacy Confirmation dated herewith between Seller and SCE, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. Reduced Monthly Capacity Payment: As set forth in Section 3.2(c) of this Confirmation. Regulation Award: For each Settlement Interval, shall mean either (i) with respect to the Performance Tolerance Band Upper Limit, the greater of the fifteen-minute HASP Regulation Up awards for the period within such Settlement Interval falls, or (ii) with respect to the Performance Tolerance Band Lower Limit, the greater of the fifteen-minute HASP Regulation Down awards for the period within such Settlement Interval falls. Regulation Down: As set forth in the Tariff. Regulation Ramp Rate: As set forth in the Tariff. Regulation Up: As set forth in the Tariff. Renewable Energy Credit: As set forth in Public Utilities Code Section 399.12(h), as may be amended from time to time or as further defined or supplemented by applicable law. Repair Plan: As set forth in Section 13.2(b) of this Confirmation. Required Natural Gas Quantity: As set forth in Section 3.1(ed)(iii) of this Confirmation. Required Payment Notice: As set forth in Section 20.4(c). Resource Adequacy Benefits: The rights and privileges attached to any generating resource that satisfy any entity’s resource adequacy obligations or requirements under any CPUC Decisions 04-01-050, 0410-035, 05-10-042, 06-04-040, 06-06-064, 06-07-031, and 07-06-029 and/or any subsequent CPUC ruling or decision, or any other resource adequacy laws, rules or regulations enacted, adopted or

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promulgated by any applicable Governmental Authority, as such decisions, rulings, laws, rules, or regulations may be amended or modified from time to time. Resource Adequacy Resource: As set forth in the Tariff. RFO Agreement: The Master Power Purchase and Sale Confirmation Letter (Energy Only UC Toll (Kern Pipeline—financially settled gas)) between the Parties, dated July 2, 2012, as may be amended from time to time. RMR Settlement Coordinator: As set forth in Section 7.2 of this Confirmation. RMR Invoice: As set forth in Section 7.2 of this Confirmation. RMR Revenue: As set forth in Section 7.2 of this Confirmation. Satellite Communications System or SCS: A system provided to Seller by SCE at SCE’s cost for emergency voice communications between SCE and Seller’s operating staff for the Generating Units. SCE Annual Test: As set forth in Section 10.2 of this Confirmation. SCE Dispatched Test: As set forth in Section 10.1 of this Confirmation. SCE Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Scheduled Energy: The Energy from a Generating Unit expected to be delivered during each Settlement Interval to the Energy Delivery Point pursuant to (a) the latest Dispatch Notice, or (b) any CAISO instructions during the Delivery Period, including (i) supplemental energy bids, or (ii) Ancillary Services exercised. If, in any Settlement Interval, the expected energy normally published by CAISO is unavailable, incomplete, or does not conform to the Operating Restrictions of the Generating UnitUnits, then for settlement purposes for that Settlement Interval only, the Scheduled Energy shall be deemed to be the Delivered Energy. Scheduling Coordinator or SC: As set forth in the Tariff. SC Replacement Date: As set forth in Section 6.4 of this Confirmation. SDD Administration Charge: As set forth in Section 8.4 of this Confirmation. SDD Admin Price: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term as defined in the Tariff. SDD Charge: A scheduling and delivery deviation charge as set forth in Section 8.3 of this Confirmation. SDD Price: For each Generating Unit, the Resource-Specific Settlement Interval LMP (as defined in the MRTU's Tariff Appendix A – “Definitions”) or any equivalent price under MRTU. In no case shall the SDD Price be less than zero (0). Self-Schedule: As set forth in the Tariff. Seller Initiated Test: As set forth in Section 10.1 of this Confirmation. Seller’s Fleet: As set forth in Section 20.3(a)(ii) of this Confirmation.

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Seller’s Proposed Test Plan: As set forth in Appendix 10.2 of this Confirmation. Settlement Agreement: The Qualifying Facility and Combined Heat and Power Program Settlement Agreement approved by the CPUC in Decision 10-12-035 issued on December 21, 2010.2010, effective November 23, 2011. Settlement Interval: As set forth in the Tariff. Shape: As set forth in Appendix 1514 of this Confirmation. Shaped Price: Shall be the price of power as determined in accordance with Appendix 1514 of this Confirmation. Site Host: The person or persons purchasing or otherwise using the Site Host Load or thermal energy output from the Generating FacilityUnits and the generating units that are subject to the obligations in the Transition PPA. Site Host Load: The electric energy and capacity produced by or associated with the Generating FacilityUnits and the generating units that are subject to the obligations in the Transition PPA that serves electrical loads (that are not Station Use) of Seller or one or more third parties conducted pursuant to California Public Utilities Code Section 218(b). Site Specific Reference Conditions: Shall have the meaning specified in Appendix 10.2 SoCalGas: Southern California Gas Company. SoCalGas Billing Meter: A revenue quality meter owned by SoCalGas (i.e., a meter meeting the standards and requirements established and maintained by SoCalGas) used to measure the quantity of natural gas delivered from the SoCalGas system to the Generating Unit for the purpose of monthly billing by SoCalGas. SoCalGas Tariff: Southern California Gas Company’s tariff filed with the CPUC, as amended or supplemented from time to time. SoCalGas Schedule No. GT-F: Firm Intrastate Transportation Service for Distribution Level Customers as provided by SoCalGas in the SoCalGas Tariff. SoCalGas Schedule No. GT-TLS: Intrastate Transportation Service for Transmission Level Customers as provided by SoCalGas in the SoCalGas Tariff. SoCalGas Transportation Contract: The natural gas transportation agreement between Seller and SoCalGas under either SoCalGas Schedule No. GT-F or SoCalGas Schedule No. GT-TLS for firm priority service in either case with sufficient capacity capable of transporting a full peak day natural gas requirement for an applicable month to each Generating Unit. SP15: The SP15 EZ Gen Hub. If the SP15 EZ Gen Hub (under any name) is not established as part of a market redesign that is implemented after the commencement of the Term, an alternative trading zone may be mutually agreed upon by the Parties in good faith that reasonably approximates the characteristics of the Existing Zone region of SP15. SP15 EZ Gen Hub: As set forth in the Tariff. Spinning Reserve: As set forth in the Tariff. Start-Up: Resulting only from a Dispatch Notice, the action of bringing the Generating Unit from shut

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down status to synchronization with the grid, attainment of its PMin, and the availability of unconditional release of such Generating Unit ready for ramping to the applicable dispatch instruction. Start-Up Aux Energy: The applicable amount of energy (MWh) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Aux Charge: The product of the applicable Start-Up Aux Energy and the sum of the “energy charge” rates (under the column headers “Delivery Service” and “Generation”) set forth in [SCEPG&E Tariff Rate Schedule TOU-8S for “Standby Service Metered and Delivered at Voltages above 50 kV at Transmission Service Voltage”] applicable to the appropriate “peak” period and in effect at the time of the applicable Start-Up. If a Start-Up falls within multiple “peak” periods (on-peak, mid-peak, or off-peak), then the Start-Up Aux Charge shall be calculated by applying the applicable “energy charge” rates to the Start-Up Aux Energy amount proportional to amount of time elapsed under each applicable “peak” period. Start-Up Charge: The applicable charge ($) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Fuel: The applicable volume of natural gas (MMBtu) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Start-Up Notice: As set forth in Section 9.2(b) of this Confirmation. Start-Up Time: The applicable amount of time (minutes) required to Start-Up the Generating Unit specified in Appendix 3.1(c) of this Confirmation. Station Use: The electrical load of the Generating Unit’s auxiliary equipment. The auxiliary equipment includes forced and induced draft fans, cooling towers, boiler feed pumps, lubricating oil systems, plant lighting, fuel handling systems, control systems, and sump pumps. Substitution Cost: As set forth in Section 6.5 of this Confirmation. Substitution Rules: As set forth in Section 6.5 of this Confirmation. Successful Repair: Immediately upon completion of the repairs to a Generating Unit, Seller demonstrates, at Seller’s expense, to SCE’s reasonable satisfaction, that such Generating Unit can: (i) Start-Up and ramp up to and remain at full load for two (2) consecutive hours, and (ii) immediately thereafter remain available to generate Energy under this Confirmation by a quantity greater than or equal to ninety-eight percent (98%) of Contract Capacity for seven (7) consecutive days. Supply Plan: As set forth in the Tariff. Tariff: The tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. Term: As set forth in Section 1.3 of this Confirmation. Test Parameters: Shall have the meaning specified in Appendix 10.2 Trading Day: The day in which Day Ahead trading occurs in accordance with the WECC Preschedule Calendar. Transfer Date 1: The first (1st) Business Day of the month in which the Auction immediately

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following the end of the Delivery Period is to take place. Transfer Date 2: The first (1st) Business Day of the month in which the Auction immediately following the end of each year during the Delivery Period that Seller must satisfy its annual compliance obligation (as described in Section 95855 of the GHG Regulations) is to take place. Transfer Date 3: The first (1st) Business Day of the month in which the Auction immediately following the end of the applicable Compliance Period is to take place, if such Compliance Period ends during the Delivery Period. Transfer Notice: As set forth in Section 20.4(b)(v). Transmission Owner: As set forth in the Tariff.

Transition Cost: The applicable fixed cost ($) required for the Generating Unit to make an MSG Transition as set forth in Appendix 3.1(c) under the heading “Fixed Transition Cost ($)”.:”. Transition Fuel: The applicable volume of natural gas (MMBtu) required for the Generating Unit to make an MSG Transition as set forth in Appendix 3.1(c) under the heading “Transition Fuel (MMBtu):”.PPA: As set forth in the Transition Cover Sheet. Transport Cost: As set forth in Section 3.1(e)(ix) of this Confirmation.Transition RA Confirmation: That certain Resource Adequacy Confirmation dated herewith between Seller and SCE, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. Turbine Configuration: As set forth in Appendix 1.8 of this Confirmation. UDP: Uninstructed Deviation Penalty, as applied to each SC by the CAISO, or any successor thereto pursuant to the Tariff. Uninstructed Deviation GMC Rate: Any administrative charge applied by the CAISO due to “Uninstructed Imbalance Energy” or successor term to UIE. Upper MW of Forbidden Region: As set forth in the “Definition” tab of the CAISO Master File. Variable O&M Charge: As set forth in Appendix 3.1(b) of this Confirmation. Variable O&M Payment: As set forth in Section 3.1(b) of this Confirmation. WECC Preschedule Calendar: The Preschedule Calendar(s) as set forth or described on the WECC website at http://www.wecc.biz.

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APPENDIX 1.4

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CONTRACT CAPACITY, ANCILLARY SERVICES AND OPERATING RESTRICTIONS Technology:

COMBUSTION TURBINE

Generating Unit Name:

Sycamore Cogeneration Company Unit 2

A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information Minimum Load, PMin (MW):

70.00

PMax (MW):

85.00

Max capacity w/o duct burners (MW):

85.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Daily Run Hours

No

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

85.00

1.00

Best Operational Minimum Down Minimum Run Ramp Rate Time (minutes): Time (minutes): (MW/min) 3.00

60.00

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Yes Ancillary Services are included: No KRCC is not currently included in Black Start Capability Plan Black Start included: Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

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Technology:

COMBUSTION TURBINE

Generating Unit Name:

Sycamore Cogeneration Company Unit 4

A. Contract Capacity and Delivery Period A.1--Contract Capacity (MW): 74.00 B. Total Unit Dispatchable Range Information Minimum Load, PMin (MW):

70.00

PMax (MW):

85.00

Max capacity w/o duct burners (MW):

85.00

Max capacity with duct burners (MW):

NA

Available after the Generating Unit has been online for (# of hours): Minimum Down Time (minutes):

60.00

Minimum Run Time (minutes):

60.00

C. Unit Start Limitations Restricted

Number of StartUps

Restricted

Number of Run Hours

Maximum Daily Start-Ups

Yes

2

Maximum Daily Run Hours

No

Maximum Weekly Start-Ups

Yes

14

Maximum Weekly Run Hours

No

Maximum Monthly Start-Ups

Yes

60

Maximum Monthly Run Hours

Yes

700.0

Yes

130

Maximum Yearly Run Hours

Yes

700.0

Maximum Yearly Start-Ups D. Multi-Stage Configuration Configuration number

Minimum Generation Capacity (MW)

Maximum Generation Capacity (MW)

Worst Operational Ramp Rate (MW/min)

1

70.00

85.00

1.00

Best Operational Minimum Down Minimum Run Ramp Rate Time (minutes): Time (minutes): (MW/min) 3.00

60.00

Description

60.00

E. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 1

F. Ancillary Services: Note that a single configuration may have multiple Regup/down or Spin/Nspin ranges and ramps Yes Ancillary Services are included: No KRCC is not currently included in Black Start Capability Plan Black Start included: Quick Start: No Regulation Up Regulation Down Configuration Number

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Regulation Ramp Rate (MW/min)

1

70.00

75.00

1.00

5.00

0.00

70.00

75.00

1.00

Spinning Reserve Configuration Number

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1] 5.00

A/S Minimum Capacity(MW) 0.00

Non Spinning Reserve A/S Maximum Capacity (MW) [1]

A/S Minimum Capacity(MW)

Lower MW

Higher MW

Operating Reserve Ramp Rate (MW/min)

A/S Maximum Capacity (MW) [1]

G. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 3

[1] As of the Confirmation Effective Date, CAISO's MRTU calculates the A/S Maximum Capacity provided by a Generating Unit based on a 10-minute period at the stated Ramp Rate. If during the Delivery Period, CAISO uses a period limitation other than the 10-minute period limitation, the A/S Maximum Capacity for each A/S and region shall be calculated according to (a) CAISO's period limitation while preserving the Ramp Rate stated for each A/S or the (b) range between the minimum A/S capacity and the maximum A/S capacity for such region, whichever is smaller.

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A/S Minimum Capacity(MW)

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APPENDIX 1.6

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ENERGY DELIVERY POINT

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Single-line diagram of grid interconnection [TO BE PROVIDED BY SELLER] [THE ENERGY DELIVERY POINT AND THE LOCATION OF THE ENERGY METERING EQUIPMENT MUST BE ACCURATELY MARKED ON THE SINGLE-LINE DIAGRAM.]

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APPENDIX 1.8 DESCRIPTION OF GENERATING UNITS AND DESCRIPTION OF SITE 1.

Generating Units Description.

a.

Generating Unit # 2 i.

Name: Sycamore Cogeneration Company Unit # 2

ii.

Location: SW China Grade Loop, Bakersfield, California

iii. CAISO Resource ID (as defined in the CAISO Tariff): As of the Confirmation Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the start of the Delivery Period, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit. iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: Unknown MW. As soon as possible, but no later than 30 days prior to the start of the Delivery Period, Seller shall provide notice to Buyer of Generating Unit NQC assigned by CAISO to this Generating Unit. v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None

b.

xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 74.00

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 100886

Generating Unit # 4 i.

Name: Sycamore Cogeneration Company Unit # 4

ii.

Location: SW China Grade Loop, Bakersfield, California

iii. CAISO Resource ID (as defined in the CAISO Tariff): As of the Confirmation Effective Date: SYCAMR_2_UNITS. As soon as possible, but no later than 30 days prior to the start of the Delivery Period, Seller shall provide notice to Buyer of CAISO Resource ID (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit.

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iv. Generating Unit NQC (as defined in the CAISO Tariff) as of the Confirmation Effective Date: Unknown MW. As soon as possible, but no later than 30 days prior to the start of the Delivery Period, Seller shall provide notice to Buyer of Generating Unit NQC (as defined in the CAISO Tariff) assigned by CAISO to this Generating Unit. v.

Resource Type: Other- Frame7E

vi.

Resource Category (1, 2, 3 or 4): 4

vii. Point of interconnection with the CAISO Controlled Grid ("Substation"): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Energy Toll viii.

Path 26 (North, South or None): South

ix.

Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura

x. Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None xi.

Existing Zone: SP15

xii.

August Net Qualifying Capacity (MW): 74.00

xiii.

Primary Fuel Type: Natural Gas

xiv.

Prime Mover Technology: Gas Turbine

xv.

Turbine Configuration: Simple Cycle (CT)

xvi.

Name Plate Capacity: 76.56

xvii.

RMR Contract: NO

xviii.

Air Pollution Control District: SJVAPCD

xix.

California Air Resources Board ID #: 100886

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2.

Site Description. Sycamore Cogeneration Company Plant Site PARCEL 1: That portion of that certain patented placer mining claim known as Amazon Placer Mining Claim described in the patent as the Southwest Quarter at the Southeast Quarter of Section 30, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area, County of Kern, State of California, according to the official plat thereof, which is included within the South 10 acres of the Southwest Quarter of the South east Quarter of said Section. Except any veins or lodes of quartz or other rock in place bearing gold, silver, cinnabar, lead, tin, copper or other valuable deposits within the land above described which may have been discovered or known to exist on or prior to August 23, 1915. PARCEL 2: The Northwest Quarter of the Northeast Quarter of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof. [TO BE PROVIDED BY SELLER] PARCEL 3: The North Half of Lot 1 of Section 31, Township 28 South, Range 28 East, Mount Diablo Meridian, in the unincorporated area of the County of Kern, State of California, according to the official plat thereof.

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APPENDIX 3.1(a) DELIVERY PERIOD AND MONTHLY CAPACITY PAYMENT

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APPENDIX 3.1(b) VARIABLE O&M CHARGE Generating Unit Name:

Sycamore Cogeneration Company Unit 2

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Generating Unit Name:

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

Sycamore Cogeneration Company Unit 4

A. Variable O&M Charge Information Figures are to be inputted to the one-hundredth level of precision (two decimal places). Contract start date and end date must be from the same calendar year. Contract Year Start Date 10/15/2012 1/1/2013 1/1/2014 1/1/2015

Contract Year End Date 12/31/2012 12/31/2013 12/31/2014 6/30/2015

59

Variable O&M Charge ($/MWh) $0.23 $0.23 $0.23 $0.23

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APPENDIX 3.1(c) START-UP CHARGE AND CAPACITY AND ANCILLARY SERVICES OPERATING RESTRICTIONS Generating Unit Name:

Sycamore Cogeneration Company Unit 2

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

0.00

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

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Generating Unit Name:

Sycamore Cogeneration Company Unit 4

A. Start-Up Information Generating Unit Start Type: Configuration Number 1

Start-Up Segment Registered Cooling Number Time (min): 1

Fast Start Unit Start-Up Time (min):

Start-Up Charge ($/Start-Up):

Start-Up Fuel (MMBtu):

Start-Up Aux Energy (MWh):

30.00

$4,100.00

235.00

0.13

0.00

B. Configuration Transition Matrix: MW levels will equal Pmax and Pmin of configurations unless an intra configuration transition is necessary Upward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Transition Ramp Time (min)

Notification Time (includes transition & prep time) (min)

Fixed Transition Cost ($)

Transition Fuel (MMBtu)

Downward Transition From Configuration Number

To Configuration Number

Maximum Daily Transitions

C. Any additional restrictions that cannot be covered by the input tables in Appendix 1.4 Page 2

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APPENDIX 5.3 HEAT RATE Generating Unit Name:

Sycamore Cogeneration Company Unit 2

A. Configuration 1 Information Minimum Generation Capacity (MW):

Maximum Generation Capacity (MW):

70.00

Heat Rate @ Pmax

85.00

12.000

Heat Rate @ Pmin

12.300

Increment (MW):

B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.300

0.00

0.00

0.00

0.00

71.00

12.240

0.00

0.00

0.00

0.00

72.00

12.180

0.00

0.00

0.00

0.00

73.00

12.120

0.00

0.00

0.00

0.00

74.00

12.060

0.00

0.00

0.00

0.00

75.00

12.000

0.00

0.00

0.00

0.00

76.00

12.000

0.00

0.00

0.00

0.00

77.00

12.000

0.00

0.00

0.00

0.00

78.00

12.000

0.00

0.00

0.00

0.00

79.00

12.000

0.00

0.00

0.00

0.00

80.00

12.000

0.00

0.00

0.00

0.00

81.00

12.000

0.00

0.00

0.00

0.00

82.00

12.000

0.00

0.00

0.00

0.00

83.00

12.000

0.00

0.00

0.00

0.00

84.00

12.000

0.00

0.00

0.00

0.00

85.00

12.000

0.00

0.00

0.00

0.00

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Generating Unit Name:

Sycamore Cogeneration Company Unit 4

A. Configuration 1 Information Minimum Generation Capacity (MW):

Maximum Generation Capacity (MW):

70.00

Heat Rate @ Pmax

85.00

12.000

Heat Rate @ Pmin

12.300

Increment (MW):

B. Heat Rate Values For calculating the Required Natural Gas Quantity, the Heat Rate applicable to a specified value of Energy ("X") (where "X" is either the Scheduled Energy or the Qualifying Delivered Energy will be identified in the table below in the following manner: (a) If "X" is a value of Energy associated with a measurement of Energy during (i) a Settlement Interval, calculate the "Hourly Output Rate" (in MW) by multiplying "X" times the number of Settlement Intervals in one (1) hour; or (ii) one (1) hour, the Hourly Output Rate (in MW) is equal to "X". (b) Take the Hourly Output Rate for "X" (as calculated in (a)) and round it down to the nearest value of Energy Output Rate (as identified in the Heat Rate Table below); if (i) the Hourly Output Rate is less than PMin, then use the PMin as the Energy Output Rate; or (ii) the Hourly Output Rate is greater than PMax, then use PMax as the Energy Output Rate. (c) The Heat Rate associated with "X" is the Heat Rate shown next to the corresponding Energy Output Rate in the Heat Rate Table below. C. Heat Rate Table Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

Energy Output Rate

Heat Rate

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

(MW)

(MMBtu/MWh)

70.00

12.300

0.00

0.00

0.00

0.00

71.00

12.240

0.00

0.00

0.00

0.00

72.00

12.180

0.00

0.00

0.00

0.00

73.00

12.120

0.00

0.00

0.00

0.00

74.00

12.060

0.00

0.00

0.00

0.00

75.00

12.000

0.00

0.00

0.00

0.00

76.00

12.000

0.00

0.00

0.00

0.00

77.00

12.000

0.00

0.00

0.00

0.00

78.00

12.000

0.00

0.00

0.00

0.00

79.00

12.000

0.00

0.00

0.00

0.00

80.00

12.000

0.00

0.00

0.00

0.00

81.00

12.000

0.00

0.00

0.00

0.00

82.00

12.000

0.00

0.00

0.00

0.00

83.00

12.000

0.00

0.00

0.00

0.00

84.00

12.000

0.00

0.00

0.00

0.00

85.00

12.000

0.00

0.00

0.00

0.00

63

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.1 AVAILABILITY NOTICE Operating Day: Station:

Issued By:

Generating Unit:

Issued At:

Generating Unit 100% Available No Restrictions: Hour Ending

Minimum Output (MW) (non AGC)

Available Capacity

AGC Available

AGC Min Limit

AGC Max Limit

(MW)

YES/NO

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

64

Comments

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.2(a) DISPATCH NOTICE Operating Day: Station:

Issued By:

Generating Unit:

Hour Ending

Issued At:

Scheduled Energy

AGC Scheduled

Regulation Up

Regulation Down

Spinning Reserve

(MW)

YES/NO

(MW)

(MW)

(MW)

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00

Comments:

65

NonSpinning Reserves (MW)

Comments

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.2(b) START-UP NOTICE Date: Station:

Issued By:

Generating Unit:

Issued At:

Date and Time Fire established in Applicable Generating Unit Date and Time Applicable Generating Unit Synchronized Date and Time Applicable Generating Unit Released for Dispatch Type of Start-Up (Hot, Warm, Cold) Fuel Consumed During Start-Up

(MMBtu)

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.2(d) DAILY OPERATING REPORT Daily Operating Reports submitted under this Confirmation should be provided in Excel. For: MM/DD/YY Plant Status at 0600 Generating Unit Name

Replicate for each Generating Unit

Current Availability (MW) Current Operating Level (MW) Current Restrictions (MW)

Prior Day Operating Level (HE)

Hourly Operating Level (Integrated)

Hourly Availability (Integrated)

Generating Unit on AS Control (Y/N)

Nature of Outage

Course of Action to Repair

Outage Date / Return Date

1:00 2:00 3:00 4:00 5:00 6:00 7:00 8:00 9:00 10:00 11:00 12:00 13:00 14:00 15:00 16:00 17:00 18:00 19:00 20:00 21:00 22:00 23:00 0:00 Total Prior Day Significant Events:

Outages (Name of Equipment)

67

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 9.2(e) COMMUNICATION PROTOCOLS Communication Protocols These Communication Protocols are subject to change and shall be modified as evolving market conditions and rules may require. 1. Contacts and Authorized Representatives The “Contact Information” tables set forth those contact functions, phone/fax numbers and e-mail information by which each Party elects to be contacted by the other. Notification provided under this Confirmation shall be made to the applicable point of contact as set forth in the Contact Information Table. A Party may update its Contact Information by providing notice to the other Party. 2. Communication Protocols: General 2.1 Intra-day Communication: All communications and notices between the Parties that occur intra-day and intra-hour for the applicable Operating Day including those regarding emergencies, Dispatch Notices, Availability Notices, and notices to avoid imbalance penalties, uninstructed deviation charges/credits or any other CAISO charges shall be provided electronically or telephonically as SCE directs to the applicable Party. If to Seller, such notices and communications shall be provided to the following contact, in order of priority, (1) ___________Dispatch Desk/Control Room, (2) ___________Plant Manager, (3) ___________Executive Director. If to SCE, such notices and communications shall be provided to the following contact, in order of priority, Real Time and Natural Gas Scheduling. Each Party shall confirm all Intra-day Communication either electronically or via telephone as soon as practicable. 2.2 Communication Failure: In the event of a failure of the primary communication link between Seller and SCE, both Parties will try all available means to communicate, including cell phones or additional communication devices as installed. 2.3 System Emergency: SCE and Seller shall communicate as soon as possible all changes to the schedule requested by the CAISO as a result of a system emergency. 2.4 Confidentiality: Confidential communications between the Parties in discharging their rights and obligations under the Confirmation and these Communication Protocols will be subject to the applicable restrictions set forth in the Confirmation. 2.5 Staffing: The Parties will have available twenty-four (24) hours a day, seven (7) days a week, personnel available to communicate regarding the implementation of these Communication Protocols.

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Contact Information Table Contacts and Authorized Representatives for SCE Outlined below is the contact and communication information for the relevant contact groups. This list may be amended by SCE with timely notice to Seller. Primary Phone

Contact

Secondary Phone

Day-Ahead Trading

626-307-4487

Day-Ahead Scheduling

626-307-4425

Gas Trading Gas Scheduling

Real Time / MSG Transition Notifications Real Time – Backup Operations Center (not staffed, emergency only) Settlements – Power & Gas

Fax

Email

626-302-3409

[email protected]

626-307-4420

626-302-3409

[email protected]

626-307-4480

626-302-4410*

626-302-3410

[email protected]

626-307-4479

626-302-4410*

626-302-3410

[email protected]

626-307-4410

Cell: 818-424-4575 Sat. Phone: 877-2482129 GOC Fly Away: 877220-9509 (only active in emergencies)

626-302-3409

[email protected] [email protected]

626-307-4410

Cell: 949-466-9909 Sat. Phone: 877-8065625

949-206-7840

[email protected] [email protected]

626-302-3277

626-302-3378

626-302-3276

[email protected]

[insert CM phone here]

626-302-8168

[insert CM email here]ESMpowercontractadmin @sce.com

Contract Administration

626-302-3216

Outage Scheduling / RA Substitution

626-302-3400

[email protected]

Availability Notices

626-302-3400

[email protected]

*Contact the Real Time Generation Desk if after hours; RT will contact the on-call Gas Trader/Scheduler

Contacts and Authorized Representatives for Seller Outlined below is the contact and communication information for the relevant Seller employees. This list may be amended by Seller with timely notice to SCE. Desk

Contact

Direct Phone

Secondary Phones

Dispatch Desk (Day-Ahead) Dispatch Desk (Real Time) Outage Desk Plant Manager

69

Fax

Email

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Contract Administration Settlements Operations Manager Operations Supervisor

70

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST [For Natural Gas Fired Boiler Generating Units] This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the procedures described in PTC 46. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). B. Test Parameters. The following Generating Unit Test parameters will be measured and recorded simultaneously at no greater than fifteen (15) minute intervals (except for fuel samples): (1) (2) (3) (4) (5) (6) (7)

instantaneous ambient inlet air relative humidity (in %) within 50 feet of the Generating Unit; instantaneous ambient inlet air temperature (in °F) within 50 feet of the Generating Unit; net Plant output measured at the Energy Delivery Point (in MW); continuous emissions monitoring system (CEMS) data required per air permit; main steam temperature (in °F); main steam pressures (in psig); and fuel flow at the natural gas meter (SCFH).

Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a qualified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters to be defined in the Final Test Plan (Part III,A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time (prior to commencing the four hour test); operated for at least four (4) hours at PMax; and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1.

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Capacity Test. Each unit will demonstrate its maximum capacity, PMax, with the following operating parameters. SELLER SHALL INSERT TABLE OF OPERATING TEMPERATURES AND PRESSURES FOR THE UNITS HERE THAT ARE PERTINENT TO THE GENERATING UNITS. In a multiple unit plant, each unit will be isolated from the other unit and provide its own auxiliary power and auxiliary steam requirements during the testing period. E. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized, and brought to PMax using normal start procedures and then operated continuously at PMax for as long as it is necessary, but in no case for no less than one (1) hour, for all measured parameters to achieve stable, normal conditions. During the course of any Test, all measured parameters will not exceed the following tolerances: Generating Unit Performance Maximum Permissible Deviations Variable

Deviation

Power Output (electrical)

±2%

Power Factor

±2%

Fuel (Natural Gas) Heating Value

±2%

Fuel Flow

± 2%

Steam Turbine Variables Main Steam Pressure Main and Reheat Steam Temperatures Feed Water Temperature Leaving Final Heater Exhaust Back Pressure

SELLER TO PROVIDE VALUES FOR EACH UNIT

F. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in PART III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the manufacturer for operation at PMax subject to any Operating Restrictions. G. Test Conditions. At all times during a Test, the Generating Unit shall not be subject to abnormal operating conditions such as: (i) unstable load conditions; (ii) equipment, operating or regulatory restrictions or (iii) changes in the Generating Unit’s electrical output other than those fluctuations arising from normal fuel control capability. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with PART II. K. below.

72

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

H. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. I. Air Emissions. The Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) - Rule 2000 (c)(18) CEMS, is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. J. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Ambient Temperature

°F (Dry Bulb)

Ambient Relative Humidity

%

Measured Net Power Output

MW

Power Factor Generating Unit Emissions

Actual and permit levels

Fuel Higher Heating Value

BTU/Cubic ft.

Note: If fuel analysis is not available by the 4th day after the Test is completed, Seller shall provide it when available or no more than ten (10) Business Days after completion of the Test. K. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with PART II. J. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf, SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives at Seller’s expense.

73

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

L. Final Report. At the later of (i) completion of fuel testing or (ii) within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 46. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3.5 of PTC 46; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. M. Operating Personnel. During any Test, regular site operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. N. SCE Representative. SCE shall be entitled to have at least three (3) representatives present to witness each Test. PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in PART II, above and in accordance with applicable Subsections of PTC 46, Section 3. At least fifteen (15) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and any temporary instrumentation. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, Seller shall calibrate or cause to be calibrated all temporary instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE at least five (5) Business Days prior to the Test.

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) for each day unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling a Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1 of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test.

75

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST [For a Simple Cycle Generating Unit] This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the relevant provisions of PTC 22. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). Site Specific Reference Conditions (provided by Seller) Turbine Compressor Inlet Air (“Inlet Air”) Temperature (in °F)

38

Inlet Air Relative Humidity (in %)

25

Barometric Pressure (inches Hg)

28.5

For each Test set forth in this Appendix, the measured test data will be corrected to the Site Specific Reference Conditions using established correction factors. The corrected test data will then be compared to the Test Parameters. B. Parameters. During any Test, at a minimum, the following parameters will be measured and recorded simultaneously for the Generating Unit at no greater than fifteen (15) minute intervals (except for fuel samples): 1) 2) 3) 4) 5) 6) 7) 8)

instantaneous Inlet Air relative humidity (%) with instruments installed in the inlet filter house; instantaneous ambient barometric pressure (inches Hg) with transmitters located near the horizontal centerline of the Generating Unit; instantaneous Inlet Air temperature (°F) with four (4) remote telemetry devices installed in an array inside the filter house; instantaneous site ambient temperature (°F); fuel flow at the Generating Unit natural gas meter (SCFH); net plant output as measured at the Energy Delivery Point (MW); heat rate (BTU/kWh) @ PMax (for testing purposes only) continuous emissions monitoring system (CEMS) data required per air permit.

76

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a qualified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters which will be defined in the Final Test Plan (Part III, A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time prior to commencing the four (4) hour test; operated for at least four (4) hours at PMaxan output, when corrected to Site Specific Reference conditions, is equal to PMax (“Full Load”); and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1. SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized and brought to PMaxFull Load using normal start procedures and then operated continuously at PMaxFull Load for as long as it is necessary, but in no case for no less than one (1) hour, for all measured parameters to achieve stable, normal conditions. During the courseany 30-minute period of any Test, all measured parameters will not exceed the values provided in Table 3-3.5 of PTC 22, “Maximum Permissible Standard Deviations of Measurements in Operating Conditions” in addition to the following: Variable Natural Gas Heating Value (Unit Volume) Absolute Inlet Air Pressure (inches H20)

Permissible Deviation ± 1.3% ± 0.33%

E. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in Part III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the equipment manufacturer for operation at PMax. F. Test Conditions. At all times during a PMaxFull Load Test, the Generating Unit shall be operated with any inlet cooling treatment systems on and such unit shall not be subject to abnormal operating conditions such as (i) ambient conditions requiring the inlet cooling system to be turned off in accordance with manufacturer’s specifications; (ii) unstable load conditions; (iii) equipment, operating or regulatory restrictions or (iv) changes in the Generating Unit’s electrical output other than those fluctuations naturally arising from variations in ambient temperature. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with Part II.J. below.

77

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

G. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. H. Air Emissions. Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) Rule 2000 (c)(18) CEMS, is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. I. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Site Ambient Air Temperature Inlet Air Temperature Inlet Air Relative Humidity Barometric Pressure Measured Net Power Output Inlet Air Treatment (Evaporative Cooler, Foggers, or Chiller) Power Factor Steam / Water Injection Generating Unit Emissions Fuel Heating Value (HHV)

°F (Dry Bulb) °F (Dry Bulb) % inches Hg MW on/off on/off (if applicable) Actual and permit levels BTU/Cubic ft

Note: If fuel analysis is not available by the fourth day after the Test is completed, Seller shall provide it on the earlier of when available or ten (10) Business Days after the Test is completed. J. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with Part II.I. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf,

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2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives, at Seller’s expense. K. Final Report. Within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 22. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8) (9)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3-5 of PTC 22; demonstration of the correction of the measured test data to the Site Specific Reference Conditions, with supporting calculations; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. L. Operating Personnel. During any Test, the same operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. M. SCE Representative. SCE shall be entitled to have at least two representatives present to witness each Test. PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in Part II, above and in accordance with applicable Subsections of PTC 22, Section 3. At least ten (10) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and the temporary instrumentation suggested by Seller or deemed necessary by SCE in its sole judgement. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with written notice of the temporary calibrated instrumentation that will be used during the Test. Seller shall calibrate or cause to be calibrated all such instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All

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electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE at least five (5) Business Days prior to the Test. Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. In addition Seller shall provide a temporary data acquisition system to monitor all temporary instruments. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling each Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1(a) of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test. G. Table. If SCE requests, Seller shall create a table relating Contract Capacity (in MW) to Inlet Air temperature, such that the Contract Capacity of the Generating Unit shall be the expected output of the Generating Unit at Test Conditions, and the expected output of the Generating Unit at other Inlet Air temperatures shall relate to Contract Capacity in the same proportion as the points on the manufacturer’s performance curve relate to that curve at Test Conditions. Such table will be provided to SCE as part of the Final Report.

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APPENDIX 10.2 TESTING PROTOCOLS SCE ANNUAL TEST [For a Combined Cycle Generating Unit] This Appendix 10.2 sets forth the protocols for the SCE Annual Test that SCE may require once per each Contract Year following the initial Contract Year and that may last up to three (3) days at SCE’s discretion. The SCE Annual Test is sometimes referred to in this Appendix as a “Test.” PART I.

GENERAL.

Each SCE Annual Test will be conducted in accordance with Accepted Electrical Practices and the relevant provisions of PTC 22 and PTC 46. The Seller and/or operator will operate the Generating Unit in its normal operating mode and use Accepted Electrical Practices during each Test. Equipment that affects the Test results will not be added, substituted or replaced during such test period. PART II.

TEST REQUIREMENTS.

A. Test Elements. A Test shall include measurement and/or determination of the Generating Unit(s) capabilities as stated in Sections A, B, D, and F, of Appendix 1.4 of this Confirmation (unless SCE, in its sole discretion, agrees otherwise in writing). Site Specific Reference Conditions (provided by Seller) Turbine Compressor Inlet Air (“Inlet Air”) Temperature (in °F) Inlet Air Relative Humidity (%) Barometric Pressure (in Hg) For each Test set forth in this Appendix, the measured test data will be corrected to the Site Specific Reference Conditions using established correction factors. The corrected test data will then be compared to the Test Parameters. B. Parameters. During any Test, at a minimum, the following parameters will be measured and recorded simultaneously for the Generating Unit at no greater than fifteen (15) minute intervals (except for fuel samples): 1) 2) 3) 4) 5) 6) 7) 8) 9) 10)

instantaneous Inlet Air relative humidity (%) with instruments installed in the inlet filter house; instantaneous ambient barometric pressure (inches Hg) with transmitters located near the horizontal centerline of the Generating Unit; instantaneous Inlet Air temperature (°F) with four (4) remote telemetry devices installed in an array inside the filter house; instantaneous site ambient temperature (°F); fuel flow at the Generating Unit natural gas meter (SCFH); net plant output as measured at the Energy Delivery Point (MW); heat rate (BTU/kWh) @ PMax (for testing purposes only); continuous emissions monitoring system (CEMS) data required per air permit; steam turbine main steam temperature (°F); steam turbine main steam pressure (psig).

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Seller shall take two (2) natural gas fuel samples at the start of the Test and two (2) natural gas fuel samples at the conclusion of the Test. Seller shall send one fuel sample from each set to a quallified independent laboratory for heating value testing at Seller’s expense. Upon mutual agreement of the Parties, additional parameters may be measured and recorded simultaneously with the required parameters which will be defined in the Final Test Plan (Part III, A). C. Test Showing. During each four (4) hour period of each Test, Seller must demonstrate to SCE’s reasonable satisfaction, that the Generating Unit: (1) (2) (3)

successfully started in its allotted time prior to commencing the four (4) hour test; operated for at least four (4) hours at PMax; and can be shut down without resorting to unusual practices or procedures, i.e., a “controlled shut down”.

At least once per Test, the Generating Unit shall also demonstrate its ability to run at PMin for one (1) hour and the ability to ramp both upwards and downwards at the rates stated in Sections D and F of Appendix 3.1. SCE in its sole discretion may elect to shorten the run periods or waive a particular portion of a Test at any time. Such election or waiver during one Test does not shorten any run period or waive any portion of any subsequent Test. D. Start-Up and Stabilization Period. Prior to the start of any Test, the Generating Unit shall be started, synchronized and brought to PMax using normal start procedures and then operated continuously at PMax for as long as it is necessary, but in no case for no less than one (1) hour. During the course of any Test, all measured parameters will not exceed the values provided in Table 3-3.5 of PTC 22, ““Maximum Permissible Standard Deviations of Measurements in Operating Conditions” in addition to the following: Variable

Permissible Deviation

Natural Gas Heating Value (Unit Volume)

± 1.3%

Absolute Inlet Air Pressure

± 0.33%

Steam Turbine Main Steam Pressure

± 3%

HRSG Main & Reheat Steam Temperature

± 30 °F

Steam Turbine Exhaust Pressure

± 0.05 PSIA or ± 2.50% - whichever is larger

E. Compliance with Final Test Plan. At all times during a Test, the Generating Unit, including all auxiliary equipment, shall be operated in compliance with the Final Test Plan as discussed in Part III of this Appendix 10.2, Accepted Electrical Practices and all operating protocols recommended, required or established by the equipment manufacturer for operation at PMax. F. Test Conditions. At all times during a PMax Test, the Generating Unit shall be operated with any inlet cooling treatment systems on and such unit shall not be subject to abnormal operating conditions such as (i) ambient conditions requiring the inlet cooling system to be turned off in accordance with the equipment manufacturer’s specifications; (ii) unstable load conditions; (iii) equipment, operating or regulatory restrictions or (iv) changes in the Generating Unit’s electrical output other than those fluctuations naturally arising from variations in ambient

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temperature. If abnormal operating conditions occur during a Test, SCE may postpone or reschedule all or part of such Test in its reasonable discretion in accordance with Part II.J. below. G. Applicable Laws and Permits. The Generating Unit shall be in compliance with all Applicable Laws and permits, including those governing safety, air, and water emissions during any Test. H. Air Emissions. Generating Unit shall be in compliance with all parameters of its air emissions permit during any Test. The Generating Unit’s validated continuous emission monitoring system (as such system is defined in South Coast Air Quality Management District’s Regulation Regional Clean Air Incentives Market (RECLAIM) - Rule 2000 (c)(18) CEMS is the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test for Generating Units located in the SCAQMD. For Generating Units located in air pollution control districts other than the SCAQMD, the preferred instrumentation for demonstrating compliance with NOx emissions requirements during the Test should be installed, maintained and operated in accordance with 40 CFR Part 75 Continuous Emission Monitoring: Subchapter C, Operation and Maintenance Requirements, which includes by reference Appendix A to part 75, Quality Assurance and Quality Control Procedures. For Generating Units subject to a federal New Source Performance Standard requiring installation of a continuous emission monitoring system, 40 CFR Part 60.13, Monitoring Requirements, and 40 CFR Part 60, Appendix B, Performance Specifications, and Appendix F. Measurement of emission of other regulated pollutants must occur during the Test to demonstrate compliance according to conditions for emissions monitoring required by the applicable Air Pollution Control District as stipulated on the Generating Unit’s permit to construct, or permit to operate. If the CEMS fails during the Test, temporary, certified emission monitoring equipment may be substituted at SCE’s sole discretion. I. Test Records. Seller shall provide records of all Test conditions no later than four (4) Business Days following completion of a Test. The records shall include copies of the raw data taken during the Test, and shall include at the minimum, the following: Site Ambient Air Temperature

°F (Dry Bulb)

Inlet Air Temperature

°F (Dry Bulb)

Inlet Air Relative Humidity

%

Barometric Pressure

Inches Hg

Measured Net Power Output

MW

Inlet Air Treatment (Evaporative Cooer, Foggers, or Chiller)

on/off

Power Factor Steam / Water Injection

on/off (if applicable)

Power Augmentation

on/off (if applicable)

Generating Unit Emissions

Actual and permit levels

Fuel Heating Value (HHV)

BTU/Cubic ft

Duct Burner Fuel Flow

BTU/Hr

Note: if fuel analysis is not available by the fourth day after the Test is completed, Seller shall provide it on the earlier of when available or ten (10) Business Days after the Test is completed.

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J. Incomplete Test. If any Test is not completed in accordance herewith, SCE may in its sole discretion as necessary to provide the most accurate results: (i) accept the Test results up to the time the Test stopped; (ii) require that the portion of the Test that was not completed be completed within a specified time period; or (iii) require that the Test be entirely repeated. Notwithstanding the above, if the Seller is unable to complete a Test due to a Seller’s Force Majeure or the actions or inactions of SCE or the CAISO, Seller shall be permitted to reconduct such Test as a Seller Initiated Test under Section 10.1 of this Confirmation on dates and at times reasonably acceptable to SCE. If the written Test records provided by Seller to SCE in accordance with Part II.I. are not in accord with the records and notes of the SCE representative who attended such Test on SCE’s behalf, SCE may require the Test to be repeated or conducted by SCE or a testing firm of SCE’s choice and attended by Sellers’s representatives, at Seller’s expense. K. Final Report. Within fifteen (15) Business Days after the completion of a Test (including a retest), Seller shall prepare and submit to SCE a written report of the Test in accordance with Section 6 of PTC 46. At a minimum, the report shall include: (1) (2) (3) (4) (5) (6) (7) (8) (9)

a copy of the Final Test Plan; a record of the personnel present during all or any part of the Test, whether serving in an operating, testing, monitoring or other such participatory role; documentation of the satisfactory completion of the Start-Up and stabilization period; a record of any unusual or abnormal conditions or events that occurred during the Test and any actions taken in response thereto; the measured Test data; a verification of the validity of the Test in accordance with Section 3.5 of PTC 46; demonstration of the correction of the measured test data to the Site Specific Reference Conditions, with supporting calculations; the level of capacity determined by the Test, including supporting calculations; and Seller’s statement of either the Seller’s acceptance of the Test or the Seller’s rejection of the Test results and reason(s) therefore.

Within ten (10) Business Days after receipt of such report, SCE shall notify Seller in writing of either SCE’s acceptance of the Test results or SCE’s rejection of the Test and reason(s) therefore. L. Operating Personnel. During any Test, the same operating personnel shall operate the Generating Unit that Seller contemplates will operate the Generating Unit during the Term. M. SCE Representative. SCE shall be entitled to have at least two representatives present to witness each Test. PART III.

SCE ANNUAL TEST

A. Test Plan. Unless the Parties agree otherwise in writing, at least sixty (60) days prior to the beginning of the Delivery Period, Seller shall prepare and submit to SCE a proposed procedure and schedule for the SCE Annual Test (“Proposed Test Plan”). Such Proposed Test Plan must comply with all requirements in Part II., above and in accordance with applicable Subsections of PTC 46, Section 3. At least ten (10) Business Days after SCE’s receipt of Seller’s Proposed Test Plan, SCE and Seller shall meet and discuss same. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with either written acceptance of same or the SCE Proposed Test Plan. Failure by SCE to provide Seller the written acceptance or the SCE Proposed Test Plan shall not constitute acceptance of Seller’s Proposed

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Test Plan. If the Parties cannot reach agreement on a Final Test Plan at least seven (7) days before the day of the Test, the SCE Proposed Test Plan shall be used as the Final Test Plan. B. Instrumentation and Metering. Unless the Parties otherwise agree in writing, Seller shall provide all instrumentation, metering and data collection equipment required to perform the Test. Instrumentation shall include all instruments permanently installed at the Generating Units and the temporary instrumentation suggested by Seller or deemed necessary by SCE in its sole judgement. Within thirty (30) days of SCE’s receipt of Seller’s Proposed Test Plan, SCE shall provide Seller with written notice of the temporary calibrated instrumentation that will be used during the Test. Seller shall calibrate or cause to be calibrated all such instrumentation, metering and data collection equipment no more than three (3) months prior to the date of the Test. All electrical metering equipment shall utilize the Generating Unit’s installed CAISO metering equipment calibrated to CAISO standards. Copies of all calibration sheets shall be provided to SCE at least five (5) Business Days prior to the Test. Permanently installed instruments shall include but not be limited to revenue metering devices located in the switchyard where Generating Units are located. Whenever possible, data will be accessed through the Generating Unit’s distributed control system. In addition Seller shall provide a temporary data acquisition system to monitor all temporary instruments. C. Test Duration. Each Test shall be for a period of four (4) consecutive hours (after stabilization period) unless SCE determines in its sole discretion that less time is needed. D. Test Dates. Seller is responsible for scheduling each Test on a day that is acceptable to SCE and that falls between June 15 and September 30 of the Contract Year in which the Test is requested. The date of any such Test shall be confirmed in writing by SCE to Seller prior to the date of the Test. The Parties should attempt but are not required to schedule such Test on days that SCE will or is likely to dispatch the Generating Unit. E. Costs. Responsibility for costs and allocation of income for an SCE Annual Test shall be as set forth in Section 10.1 of this Confirmation. F. No Adjustment to Contract Capacity. Contract Capacity shall not be adjusted to conform to the results of any SCE Annual Test. G. Table. If SCE requests, Seller shall create a table relating Contract Capacity (in MW) to Inlet Air temperature, such that the Contract Capacity of the Generating Unit shall be the expected output of the Generating Unit at Test Conditions, and the expected output of the Generating Unit at other Inlet Air temperatures shall relate to Contract Capacity in the same proportion as the points on the manufacturer’s performance curve relate to that curve at Test Conditions. Such table will be provided to SCE as part of the Final Report.

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APPENDIX 11.1 PLANNED OUTAGE REPORT

Planned Outage Reports submitted under this Confirmation should be provided in Excel.

DATE OF UPDATE RESOURCE NAME Replicate for each Generating Unit

Planned Outages Start Date

HE

End Date

86

HE

MW Available

Cause

Emergency Time of Return

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APPENDIX 12.3 DELIVERY OF DATA The following is a list of real time generic data points to be electronically exchanged between Seller and SCE. SCE may add items to or delete items from this list at its reasonable discretion prior to the beginning of the Delivery Period. Additional meetings will be scheduled to clarify and finalize points list prior to configuration tasks.

Point description: From Generator DNP - XXX UNIT# Breaker DNP - XXX UNIT# AGC CTRL AVAILABILITY ONOFF DNP - XXX UNIT# ISO RIG Lost Communication DNP - XXX UNIT# High Operating Limit DNP - XXX UNIT# Low Operating Limit DNP - XXX UNIT# ISO AGC set point DNP - XXX UNIT# Net MW (POD) DNP - XXX UNIT# Capacity DNP - XXX UNIT# Max Sustained Ramp Rate

From GMS Control Related DNP - XXX UNIT# AGC model - ISO AGC DNP - XXX UNIT# AGC model – SFM DNP - XXX UNIT# AGC model – MAN DNP - XXX UNIT# AGC model – OFF DNP - XXX UNIT# Dispatch Energy Schedule "GO TO" DNP - XXX UNIT# Reg Up Awarded MW DNP - XXX UNIT# Reg Down Awarded MW DNP - XXX UNIT# Spin Awarded MW DNP - XXX UNIT# Non-Spin Awarded MW DNP - XXX UNIT# Set Point (MW) DNP - XXX UNIT# Ramp Rate (MW/M)

From GMS Schedules Related DNP - SCH HA Today XXX UNIT# HE01 DNP - SCH HA Today XXX UNIT# HE02 DNP - SCH HA Today XXX UNIT# HE03 DNP - SCH HA Today XXX UNIT# HE04 DNP - SCH HA Today XXX UNIT# HE05 DNP - SCH HA Today XXX UNIT# HE06 DNP - SCH HA Today XXX UNIT# HE07 DNP - SCH HA Today XXX UNIT# HE08 DNP - SCH HA Today XXX UNIT# HE09 DNP - SCH HA Today XXX UNIT# HE10 DNP - SCH HA Today XXX UNIT# HE11 DNP - SCH HA Today XXX UNIT# HE12 DNP - SCH HA Today XXX UNIT# HE13

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From GMS Schedules Related (cont.) DNP - SCH HA Today XXX UNIT# HE14 DNP - SCH HA Today XXX UNIT# HE15 DNP - SCH HA Today XXX UNIT# HE16 DNP - SCH HA Today XXX UNIT# HE17 DNP - SCH HA Today XXX UNIT# HE18 DNP - SCH HA Today XXX UNIT# HE19 DNP - SCH HA Today XXX UNIT# HE20 DNP - SCH HA Today XXX UNIT# HE21 DNP - SCH HA Today XXX UNIT# HE22 DNP - SCH HA Today XXX UNIT# HE23 DNP - SCH HA Today XXX UNIT# HE24 DNP - SCH HA Today XXX UNIT# HE25 DNP - SCH HA Tomorrow XXX UNIT# HE01 DNP - SCH HA Tomorrow XXX UNIT# HE02 DNP - SCH HA Tomorrow XXX UNIT# HE03 DNP - SCH HA Tomorrow XXX UNIT# HE04 DNP - SCH HA Tomorrow XXX UNIT# HE05 DNP - SCH HA Tomorrow XXX UNIT# HE06 DNP - SCH HA Tomorrow XXX UNIT# HE07 DNP - SCH HA Tomorrow XXX UNIT# HE08 DNP - SCH HA Tomorrow XXX UNIT# HE09 DNP - SCH HA Tomorrow XXX UNIT# HE10 DNP - SCH HA Tomorrow XXX UNIT# HE11 DNP - SCH HA Tomorrow XXX UNIT# HE12 DNP - SCH HA Tomorrow XXX UNIT# HE13 DNP - SCH HA Tomorrow XXX UNIT# HE14 DNP - SCH HA Tomorrow XXX UNIT# HE15 DNP - SCH HA Tomorrow XXX UNIT# HE16 DNP - SCH HA Tomorrow XXX UNIT# HE17 DNP - SCH HA Tomorrow XXX UNIT# HE18 DNP - SCH HA Tomorrow XXX UNIT# HE19 DNP - SCH HA Tomorrow XXX UNIT# HE20 DNP - SCH HA Tomorrow XXX UNIT# HE21 DNP - SCH HA Tomorrow XXX UNIT# HE22 DNP - SCH HA Tomorrow XXX UNIT# HE23 DNP - SCH HA Tomorrow XXX UNIT# HE24 DNP - SCH HA Tomorrow XXX UNIT# HE25

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APPENDIX 13.3(b) HISTORICAL OUTAGE REPORT [To be provided by Seller]APPENDIX 13.3(c) DISCLOSURE SCHEDULE [To be provided by Seller] None

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APPENDIX 1513.3(d) HISTORICAL OUTAGE REPORT SYCAMORE COGENERATION COMPANY GENERATING UNIT # 2 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2 2

Available Time Thu 01Jan09 00:00 Mon 12Jan09 11:14 Tue 13Jan09 12:00 Wed 14Jan09 16:07 Thu 15Jan09 12:18 Mon 23Feb09 09:06 Tue 10Mar09 07:50 Thu 23Apr09 08:54 Fri 08May09 02:04 Sun 17May09 15:44 Sun 17May09 17:02 Thu 04Jun09 03:41 Tue 09Jun09 11:42 Fri 18Sep09 07:30 Fri 18Sep09 10:09 Tue 22Sep09 01:45 Thu 24Sep09 11:21 Tue 29Sep09 12:00 Fri 06Nov09 12:00 Tue 09Feb10 20:12 Sat 20Feb10 17:24 Wed 24Feb10 14:30 Mon 22Mar10 16:49 Tue 23Mar10 06:43 Tue 29Jun10 00:36 Mon 05Jul10 13:42 Fri 09Jul10 00:51 Tue 20Jul10 09:48 Wed 04Aug10 09:13 Fri 27Aug10 10:44 Tue 04Jan11 09:29 Sun 09Jan11 12:10 Sun 09Jan11 18:31 Thu 09Jun11 09:46 Tue 21Jun11 12:11 Fri 24Jun11 13:58 Mon 27Jun11 12:23 Sat 03Dec11 10:02 Wed 07Dec11 08:28 Thu 08Dec11 07:50 Fri 13Jan12 07:32 Fri 27Jan12 04:47 Fri 27Jan12 12:41 Mon 06Feb12 10:34 Fri 17Feb12 07:50 Fri 24Feb12 08:45 Wed 07Mar12 08:11 Wed 07Mar12 09:08

UnAvailable Time Fri 09Jan09 10:55 Mon 12Jan09 11:46 Tue 13Jan09 13:44 Wed 14Jan09 17:06 Mon 23Feb09 06:06 Tue 10Mar09 07:08 Tue 21Apr09 10:19 Fri 08May09 01:33 Sun 17May09 14:30 Sun 17May09 16:34 Thu 04Jun09 03:10 Tue 09Jun09 11:12 Mon 14Sep09 00:01 Fri 18Sep09 08:22 Tue 22Sep09 01:12 Wed 23Sep09 12:12 Mon 28Sep09 00:05 Mon 02Nov09 07:00 Tue 09Feb10 19:43 Sat 20Feb10 16:48 Wed 24Feb10 13:58 Mon 22Mar10 16:18 Tue 23Mar10 05:42 Tue 29Jun10 00:06 Mon 05Jul10 12:52 Fri 09Jul10 00:31 Tue 20Jul10 09:32 Tue 03Aug10 07:00 Fri 27Aug10 10:13 Tue 04Jan11 05:42 Sun 09Jan11 07:02 Sun 09Jan11 15:54 Thu 09Jun11 08:04 Tue 21Jun11 11:42 Fri 24Jun11 12:00 Mon 27Jun11 12:04 Sat 03Dec11 08:10 Tue 06Dec11 22:02 Wed 07Dec11 20:35 Fri 13Jan12 07:00 Fri 27Jan12 04:04 Fri 27Jan12 12:29 Mon 06Feb12 10:24 Thu 16Feb12 17:34 Fri 24Feb12 07:25 Wed 07Mar12 01:57 Wed 07Mar12 08:49 Tue 01May12 00:00 Total Available Hours TotalHours % Available

Available Hours 202.9 0.5 1.7 1.0 929.8 358.0 1010.5 352.6 228.4 0.8 418.1 127.5 2316.3 0.9 87.0 34.5 84.7 811.0 2287.7 260.6 92.6 625.8 12.9 2345.4 156.3 82.8 272.7 333.2 553.0 3115.0 117.6 3.7 3613.5 289.9 71.8 70.1 3811.8 84.0 12.1 863.2 332.5 7.7 237.7 247.0 167.6 281.2 0.6 1310.9 28,627.3 29,184.0 98.1%

Unavailable Hours 72.3 24.2 26.4 19.2 3.0 0.7 46.6 0.5 1.2 0.5 0.5 0.5 103.5 1.8 0.5 23.2 35.9 101.0 0.5 0.6 0.5 0.5 1.0 0.5 0.8 0.3 0.3 26.2 0.5 3.8 5.1 2.6 1.7 0.5 2.0 0.3 1.9 10.4 11.3 0.5 0.7 0.2 0.2 14.3 1.3 6.2 0.3 0.0 556.7

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Reason UnAvailable Shutdown due to Emissions Exceedence Emissions Exceedence - CLEC Maintenance Emissions Exceedence - Rebooted RSTC Computers Emissions Exceedence Troubleshooting Crankwash Emissions Exceedence - Reset and Restarted NERC Required Transformer Inspection - Crankwash Combustion Dynamics Erratic - Reset and Restarted CLEC System Trouble - Reset and Restarted Unit CLEC System Trouble - Reset and Restarted Unit Unit Tripped - Failure to Reignite Primaries Emissions Exceedence - Restarted Combustion Inspection Combustion Inspection- Testing Emissions Exceedence - Restarted Secondary Fuel Nozzle Mainenancee Inspect Primary Fuel Nozzles for leakage Mini Combustion Inspection Unit Shutdown due to Flashbacks - Restarted Emissions Exceedence - Reset and Restarted Unit Shutdown due to Flashbacks - Restarted Unit Shutdown due to Flashbacks - Restarted Emissions Exceedence - Replaced by Unit 4 Manual shutdown due to Flashbacks - Reset and Restarted Unit Manual shutdown due to Flashbacks Manual shutdown due to Flashbacks Manual shutdown due to Flashbacks Replaced Secondary Fuel Nozzles Flashback and Trip During OnLine Wash - Reset and Restarted High CO Emissions High CO Emissions High CO Emissions Cleaned dirty flame detectors Over excitation trip due to voltage swing during voltage adjustment - restarted Over excitation trip due to voltage swing during voltage adjustment - restarted Over excitation trip due to voltage swing during voltage adjustment - restarted Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Flashbacks - Emissions Exceedence Flashbacks - Emissions Exceedence Investigate Unstable Flame in Secondary Burners - Extra Unit Emissions Exceedence required shutdown Emissions Exceedence required shutdown End of File

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SYCAMORE COGENERATION COMPANY GENERATING UNIT # 4 AVAILABILITY - January 1, 2009 to May 1, 2012 Unit 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4 4

Available Time Thu 01Jan09 00:00 Mon 09Mar09 03:22 Tue 21Apr09 09:49 Wed 02Sep09 14:18 Sat 03Oct09 18:55 Mon 16Nov09 11:43 Thu 07Jan10 01:04 Sat 09Jan10 09:59 Sat 09Jan10 12:43 Sun 10Jan10 07:54 Sun 10Jan10 11:05 Mon 11Jan10 04:32 Sun 18Apr10 23:48 Sat 22May10 15:43 Sat 08Jan11 14:35 Mon 21Feb11 21:41 Tue 01Nov11 00:00 Fri 09Dec11 01:47 Wed 11Jan12 07:19 Wed 11Jan12 09:59 Thu 12Jan12 06:25 Thu 16Feb12 09:18 Fri 17Feb12 07:50 Fri 17Feb12 19:32 Sat 25Feb12 14:32 Fri 02Mar12 23:33 Tue 06Mar12 20:34 Wed 07Mar12 09:08 Fri 06Apr12 06:20

UnAvailable Time Mon 09Mar09 02:48 Thu 09Apr09 11:01 Wed 02Sep09 13:45 Sat 03Oct09 02:12 Mon 16Nov09 10:13 Thu 07Jan10 00:56 Sat 09Jan10 03:09 Sat 09Jan10 11:25 Sun 10Jan10 07:20 Sun 10Jan10 10:33 Mon 11Jan10 03:21 Sun 18Apr10 21:37 Sat 22May10 13:39 Sun 02Jan11 10:27 Mon 21Feb11 21:06 Mon 24Oct11 07:00 Fri 09Dec11 01:36 Wed 11Jan12 03:52 Wed 11Jan12 09:26 Thu 12Jan12 05:53 Mon 13Feb12 07:00 Thu 16Feb12 15:32 Fri 17Feb12 18:55 Sat 25Feb12 13:58 Fri 02Mar12 23:02 Tue 06Mar12 19:59 Tue 06Mar12 23:02 Fri 06Apr12 05:31 Tue 01May12 00:00 Total Available Hours TotalHours % Available

Available Hours 1610.8 751.6 3219.9 731.9 1047.3 1237.2 50.1 1.4 18.6 2.6 16.3 2345.1 805.8 5394.7 1062.5 5865.3 913.6 794.1 2.1 19.9 768.6 6.2 11.1 186.4 152.5 92.4 2.5 716.4 593.7 28,420.8 29,184.0 97.4%

Unavailable Hours 0.6 286.8 0.6 16.7 1.5 0.1 6.8 1.3 0.6 0.5 1.2 2.2 2.1 148.1 0.6 185.0 0.2 3.4 0.6 0.5 74.3 16.3 0.6 0.6 0.5 0.6 10.1 0.8 0.0 763.2

91

Reason UnAvailable Emissions Exceedence - CLEC valve maintenance CEMS Multi-Port System Installed - NERC Inspection - CW Reset C Computer Following Computer Trip DCS/Ovation Upgrade Unit Accidentally Tripped during Switchyard relay maintenance Shutdown to Troubleshoot Flash Back Cause Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Emissions Exceedence High CO - Reset and Restarted Tripped on Loss Of Flame - Cleaned Flame Detectors Replaced Failed Flame Detectors #7 & #8 Combustion Inspection High Nox Emissions Exhaust Duct Maintenance Emissions Exceedence required shutdown Flashback - Failed to re-ignite primaries Emissions Exceedence required shutdown Emissions Exceedence required shutdown Mini Combustion Inspection - Fuel Nozzles replaced Replaced #9 Secondary Fuel Nozzle Emissions Exceedence required shutdown High Combustion Dynamics Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown Emissions Exceedence required shutdown End of File

2012 CHP Energy Only UC Toll (inside SoCalGasKern Pipeline--financially settled gas)

APPENDIX 14 SHAPED PRICE CALCULATION 1

Shape Calculation a) “Shape” shall be the ratio, expressed as a percentage, of a Forward Price Assessment of (i) the price of power for a calendar quarter to the price of power for the calendar year that such quarter falls within, or (ii) the price of power for a month to the price of power for the quarter that such month falls within. b) There are four quarterly Shapes (for the first through fourth calendar quarters) and twelve monthly Shapes (for the months of January through December) in every calendar year. 1.

For purposes of determining the applicable quarterly Shape, an annual price is calculated as the simple average of the four quarterly prices within the last available year. For example, the first quarter Shape is calculated using the formula below: ShapeQ1 = PQ1 / Average (PQ1 + PQ2 + PQ3 + PQ4)

2.

For purposes of determining the applicable monthly Shape, a quarterly price is calculated as the simple average of the three monthly prices within the applicable quarter. For example, the January Shape is calculated using the formula below: ShapeJan = PJan / Average (PJan + PFeb + PMar)

2

Calculation of Shaped Prices “Shaped Price” shall mean, if there is no Forward Price Assessment for the relevant calendar month, the price of power calculated in accordance with the following process. If no monthly price is available for a Forward Price Assessment but a quarterly price is available, then use a monthly Shape to calculate a monthly Shaped Price from a quarterly price using the following formula: PM = PQ × ShapeM Where: PM is the missing monthly power price PQ is the quarterly power price applicable to the relevant calendar month ShapeM is the applicable “Shape” for the missing month If no monthly or quarterly price is available for a Forward Price Assessment but an annual price is available, then use a quarterly Shape to calculate a quarterly Shaped Price from an annual price using the following formula: PQ = PY × ShapeQ Where: PQ is the missing quarterly power price PY is the yearly power price applicable to the applicable calendar quarter ShapeQ is the applicable “Shape” for the missing quarter

92

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776

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

PARAGRAPH 10 to the COLLATERAL ANNEX to the EEI MASTER POWER PURCHASE AND SALE AGREEMENT Between ____Sycamore Cogeneration Company (“Party A”) and Southern California Edison Company (“SCE” or “Party B”) CREDIT ELECTIONS COVER SHEET Paragraph 10. Elections and Variables I.

Collateral Threshold. A.

Party A Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party A shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party A; and provided further that, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party A Collateral Threshold” opposite the Credit Rating for [Party A][Party A’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party A][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing; provided, however, in the event that, and on the date that, Party A cures the Potential Event of Default on or prior to the date that Party A is required to post Performance Assurance to Party B pursuant to a demand made by Party B pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party A shall automatically increase from zero to the Threshold Amount and (ii) Party A shall be relieved of its obligation to post Performance Assurance pursuant to such demand. Party A Collateral Threshold $__________ $__________ $__________ $__________ $__________



Credit Rating _______ (or above) _______ _______ _______ Below _______

The amount (“Threshold Amount”) which is the lowest of:

(1) the amount set forth below under the heading “Party A Collateral Threshold” opposite the lower of the Credit Ratings for Party A or, if applicable, Party A’s Guarantor on the relevant date of determination. If Party A or, if applicable, its Guarantor is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party A or, if applicable, its Guarantor is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party A or, if applicable,

11

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

its Guarantor does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) 80% of the amount of the guaranty agreement, as amended from time to time, provided by Party A’s Guarantor, if any, for the benefit of Party B; or (3) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party A has occurred and is continuing: Party A Collateral Threshold (in thousands of US Dollars) $[To be negotiated] 0 (zero) $[To be negotiated] 0 (zero) $[To be negotiated] 0 (zero) $[To be negotiated] 0 (zero) $[To be negotiated] 0 (zero) $[To be negotiated] 0 (zero) $[To be negotiated] 0 (zero) $ 0 (zero)

B.

Moody’s Credit Rating

S&P Credit Rating

Fitch Credit Rating

Aa3 or above

AA- or above

AA- or above

A1

A+

A+

A2

A

A

A3

A-

A-

Baa1

BBB+

BBB+

Baa2

BBB

BBB

Baa3

BBB-

BBB-

Ba1 or below

BB+ or below

BB+ or below



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party A’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Party B Collateral Threshold. 

$______________ (the “Threshold Amount”); provided, however, that the Collateral Threshold for Party B shall be zero upon the occurrence and during the continuance of an Event of Default or a Potential Event of Default with respect to Party B; and provided further that, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand.



(a) The amount (the “Threshold Amount”) set forth below under the heading “Party B Collateral Threshold” opposite the Credit Rating for [Party B][Party B’s Guarantor] on the relevant date of determination, or (b) zero if on the relevant date of determination [Party B][its Guarantor] does not have a Credit Rating from the Ratings Agency specified below or an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing; provided, however, in the event that, and on the date that, Party B cures the Potential Event of Default on or prior to the date that Party B is required to post Performance Assurance to Party A pursuant to a demand made by Party A pursuant to the provisions of the Transition Collateral Annex on or after the occurrence of such Potential Event of Default, (i) the Collateral Threshold for Party B shall automatically increase from

22

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

zero to the Threshold Amount and (ii) Party B shall be relieved of its obligation to post Performance Assurance pursuant to such demand:



Party B Collateral Threshold

_____Credit Rating

$__________ $__________ $__________ $__________ $__________

_______ (or above) _______ _______ _______ Below _______

The amount (the “Threshold Amount”) which is the lower of:

(1) the amount set forth below under the heading “Party B Collateral Threshold” opposite the lower of the Credit Ratings for Party B on the relevant date of determination. If Party B is rated by only two of the Ratings Agencies specified below, then the lower Credit Rating shall apply. If Party B is rated by only one of the Ratings Agencies specified below, then that Credit Rating shall apply. If Party B does not have a Credit Rating from at least one of the Ratings Agencies specified below, the Collateral Threshold shall be $0 (zero); (2) $0 (zero) if an Event of Default or a Potential Event of Default with respect to Party B has occurred and is continuing: Party B Moody’s S&P Fitch Collateral Threshold Credit Rating Credit Rating Credit Rating (in thousands of US Dollars) $[To be negotiated] 0 Aa3 or above AA- or above AA- or above (zero) $[To be negotiated] 0 A1 A+ A+ (zero) $[To be negotiated] 0 A2 A A (zero) $[To be negotiated] 0 A3 AA(zero) $[To be negotiated] 0 Baa1 BBB+ BBB+ (zero) $[To be negotiated] 0 Baa2 BBB BBB (zero) $[To be negotiated] 0 Baa3 BBBBBB(zero) $ 0 (zero) Ba1 or below BB+ or below BB+ or below

II.



The amount of the Guaranty Agreement dated _____ from _____, as amended from time to time but in no event shall Party B’s Collateral Threshold be greater than $______.



Other – see attached threshold terms

Eligible Collateral and Valuation Percentage. The following items will qualify as "Eligible Collateral" for the Party specified:

(A)

Cash

Party A

Party B

[X]

[X]

33

Valuation Percentage 100%

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

III.

(B)

Letters of Credit

(C)

Other

[X]

[X]

[ ]

[ ]

100% unless either (i) a Letter of Credit Default shall have occurred and be continuing with respect to such Letter of Credit, or (ii) twenty (20) or fewer Business Days remain prior to the expiration of such Letter of Credit, in which cases the Valuation Percentage shall be zero (0%). ________%

Independent Amount. A.

Party A Independent Amount. 

Party A shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount option is selected for Party A, then Party A (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party B (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party A’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex. Party A shall have a Full Floating Independent Amount of (i) the amount specified in a Transaction or Confirmation, if any; and (ii) if Party A’s Credit Rating is lower than BBBby S&P, Baa3 by Moody’s, or BBB- by Fitch, the amount equal to ten percent (10%) of the market value of all outstanding Transactions (except those for which an alternative Independent Amount is specified in the Confirmation), adjusted by the netting of the market value of purchases with the market value of sales within the same billing cycles. If the Full Floating Independent Amount option is selected for Party A, then for purposes of calculating the Collateral Requirements pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party A shall be added to the Exposure Amount for Party B and subtracted from the Exposure Amount for Party A. [This option is applicable if Party A does not have investment grade Credit Ratings.] Party A shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party A, then Party A will be required to Transfer or cause to be Transferred to Party B Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party A otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced so long as Party A has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex. Not Applicable. [This option is applicable if Party A or its Guarantor has investment grade Credit Ratings.]

B.

Party B Independent Amount.

44

Paragraph 10 to the Collateral Annex SCE v.09.17.2008



Party B shall have a Fixed Independent Amount of $______________. If the Fixed Independent Amount Option is selected for Party B, then Party B (which shall be a Pledging Party with respect to the Fixed IA Performance Assurance) will be required to Transfer or cause to be Transferred to Party A (which shall be a Secured Party with respect to the Fixed IA Performance Assurance) Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Fixed IA Performance Assurance”). The Fixed IA Performance Assurance shall not be reduced for so long as there are any outstanding obligations between the Parties as a result of the Agreement, and shall not be taken into account when calculating Party B’s Collateral Requirement pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Fixed IA Performance Assurance shall be held and maintained in accordance with, and otherwise be subject to, Paragraphs 2, 5(b), 5(c), 6, 7 and 9 of the Transition Collateral Annex. Party B shall have a Full Floating Independent Amount of $______________. If the Full Floating Independent Amount Option is selected for Party B then for purposes of calculating Party B’s Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Party B shall be added by Party A to its Exposure Amount for purposes of determining Net Exposure pursuant to Paragraph 3(a) of the Transition Collateral Annex.



Party B shall have a Partial Floating Independent Amount of $______________. If the Partial Floating Independent Amount option is selected for Party B, then Party B will be required to Transfer or cause to be Transferred to Party A Performance Assurance with a Collateral Value equal to the amount of such Independent Amount (the “Partial Floating IA Performance Assurance”) if at any time Party B otherwise has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount) pursuant to Paragraph 3 of the Transition Collateral Annex. The Partial Floating IA Performance Assurance shall not be reduced for so long as Party B has a Collateral Requirement (not taking into consideration the Partial Floating Independent Amount). The Partial Floating Independent Amount shall not be taken into account when calculating a Party’s Collateral Requirements pursuant to the Transition Collateral Annex. Except as expressly set forth above, the Partial Floating Independent Amount shall be held and maintained in accordance with, and otherwise be subject to, the Transition Collateral Annex. Not Applicable.

IV.

V.

VI.

Minimum Transfer Amount. A.

Party A Minimum Transfer Amount:

$0.00

B.

Party B Minimum Transfer Amount:

$0.00

Rounding Amount. A.

Party A Rounding Amount:

$250,000.00

B.

Party B Rounding Amount:

$250,000.00

Administration of Cash Collateral. A.

Party A Eligibility to Hold Cash. 

Party A shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral

55

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B. 

Party A shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party A or, if applicable, Party A’s Guarantor has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party A or its Guarantor has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or on “Credit Watch” negative or developing by Fitch, then Party A shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party A is entitled to hold Cash, the Interest Rate payable to Party B on Cash shall be as selected below: Party A Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

To the extent that Party A is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party A shall pay to Party B in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party B. B.

Party B Eligibility to Hold Cash. 

Party B shall not be entitled to hold Performance Assurance in the form of Cash. Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A.



Party B shall be entitled to hold Performance Assurance in the form of Cash provided that the following conditions are satisfied: (1) it is not a Defaulting Party; (2) Party B has a Credit Rating of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency; and (3) Cash shall be held only in any jurisdiction within the United States. Notwithstanding the foregoing, in the event Party B has a Credit Rating of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch with a negative or developing outlook, or if such a Credit Rating is on “Credit Watch” negative or developing by S&P, on “Watchlist” under review for downgrade or uncertain ratings action by Moody’s, or “Credit Watch” negative or developing by Fitch, then Party B shall not be entitled to hold Performance Assurance in the form of Cash. To the extent Party B is entitled to hold Cash, the Interest Rate payable to Party A on Cash shall be as selected below:

66

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

Party B Interest Rate. 

Federal Funds Effective Rate - the rate for that day opposite the caption "Federal Funds (Effective)" as set forth in the weekly statistical release designated as H.15(519), or any successor publication, published by the Board of Governors of the Federal Reserve System.



Other - ____________

To the extent that Party B is not entitled to hold Cash, Performance Assurance in the form of Cash shall be held in a Qualified Institution in accordance with the provisions of Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. Party B shall pay to Party A in accordance with the terms of the Transition Collateral Annex the amount of interest it receives from the Qualified Institution on any Performance Assurance in the form of Cash posted by Party A. VII.

Notification Time. 10:00 a.m. Pacific Prevailing Time on a Local Business Day.

VIII.

General. With respect to the Collateral Threshold, Independent Amount, Minimum Transfer Amount and Rounding Amount, if no selection is made in this Cover Sheet with respect to a Party, then the applicable amount in each case for such Party shall be zero (0). In addition, with respect to the “Administration of Cash Collateral” section of this Paragraph 10, if no selection is made with respect to a Party, then such Party shall not be entitled to hold Performance Assurance in the form of Cash and such Cash, if any, shall be held in a Qualified Institution pursuant to Paragraph 6(a)(ii)(B) of the Transition Collateral Annex. If a Party is eligible to hold Cash pursuant to a selection in this Paragraph 10 but no Interest Rate is selected, then the Interest Rate for such Party shall be the Federal Funds Effective Rate as defined in Section VI of this Paragraph 10.

IX.

Other Changes. The following changes to the Collateral Annex shall be applicable. A.

Introduction. The first paragraph of the introduction is amended to read as follows: “This Collateral Annex, together with the Paragraph 10 Cover Sheet, (the “Transition Collateral Annex”) supplements, forms a part of, and is subject to the EEI Master Power Purchase and Sale Agreement dated as of _________October 15, 2012 between _________Sycamore Cogeneration Company (“Party A”) and Southern California Edison Company (“Party B”), including the Cover Sheet and any other annexes thereto (as amended and supplemented from time to time, the “Agreement”). Capitalized terms used in this Transition Collateral Annex but not defined herein shall have the meanings given such terms in the Agreement.”

B.

Paragraph 1. Definitions. Amend Paragraph 1 as follows: i. The definition of “Credit Rating” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.12 of the Transition Master Agreement as modified in the Cover Sheet. ii. The definition of “Credit Rating Event” is amended by replacing “6(a)(iii)” with “6(a)(ii)”. iii. The definition of “Downgraded Party” is amended by replacing “6(a)(i)” with “6(a)(ii)”.

77

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

iv. The definition of “Letter of Credit” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.27 of the Transition Master Agreement as modified in the Cover Sheet. v. The definition of “Letter of Credit Default” is amended by replacing the word “or” in the third line with the word “and”. vi. The definition of “Local Business Day” is amended by replacing the word “day” with “Business Day”. vii. The definition of “Notification Time” is amended by replacing “11:00, New York” with “10:00 a.m. Pacific Prevailing.” viii. The definition of “Performance Assurance” is amended by replacing “6(a)(iv)” with “6(a)(iii)”. ix. The definition of “Qualified Institution” is amended as follows: “ “Qualified Institution” means a commercial bank or trust company organized under the laws of the United States or a political subdivision thereof, with (i) a Credit Rating of at least (a) "A-" by S&P, "A3" by Moody's, and “A-” by Fitch, if such entity is rated by all three Ratings Agencies; or (b) "A-" by S&P, "A3" by Moody's, or “A-” by Fitch, if such entity is rated by only two Ratings Agencies, and (ii) having a capital surplus of at least ONE BILLION AND 00/100 DOLLARS ($1,000,000,000.00).” x. The definition of “Reference Market-maker” is deleted from the Collateral Annex and all references shall have the meaning set forth in Section 1.671.71 of the Transition Master Agreement as modified in the Cover Sheet. xi. The definition of “Secured Party” is amended by replacing “3(b)” with “3(a)”. C.

Paragraph 3. Calculations of Collateral Requirement. In Paragraph 3(b)(2), is amended by replacing the comma after “Secured Party” with “and” and by deleting the phrase “, and any Interest Amount that has not yet been Transferred to the Pledging Party”.

D.

Paragraph 4. Delivery of Performance Assurance. In Paragraph 4, the penultimate sentence is amended by replacing the words “next Local Business Day” with “third Local Business Day thereafter” in clause (i), and by replacing the word “second” with fourth” in clause (ii).

E.

Paragraph 5. Reduction and Substitution of Performance Assurance. Amend Paragraph 5 as follows: i. Paragraph 5(a) is amended by deleting the parenthetical “(but no more frequently than weekly with respect to Letters of Credit and daily with respect to Cash)” from the first line. ii. The sixth sentence of Paragraph 5(a) is amended by inserting the word “Local” before “Business Day,” in clause (i) of that sentence.

F.

Paragraph 6. Administration of Performance Assurance. Amend Paragraph 6 as follows: i. Paragraph 6(a)(ii)(A) is amended by inserting “(other than subparagraph (B) below)” after “the provisions of this Paragraph 6(a)(ii)” in the first line thereof. ii. Paragraph 6(a)(ii)(B) is amended by replacing “Non-Downgraded Party” with “Downgraded Party”. iii. Paragraph 6(b)(iv) is amended by capitalizing the second instance of the word “cash” in the second sentence.

88

Paragraph 10 to the Collateral Annex SCE v.09.17.2008

iv. Paragraph 6(b)(v) is amended by replacing the parenthetical phrase “(including but not limited to the reasonable costs, expenses, and attorneys’ fees of the Secured Party)” with “(excluding attorneys’ fees)”. G.

Paragraph 7. Exercise of Rights Against Performance Assurance. Paragraph 7(b) is amended by deleting it in its entirety and inserting the words “Intentionally Omitted.”.

H.

Paragraph 8. Disputed Calculations. Amend Paragraph 8 as follows: i. Paragraph 8(a) is amended by adding in the third sentence the phrase “and, provided further, that if no quotations can be obtained, then the Secured Party’s original calculation shall be used” immediately after the words “then that quotation shall be used” and before the “)”. ii. Paragraph 8(b) is amended by (1) adding the words “requested by the Pledging Party” between the word “Assurance” and the phrase “to be reduced”, and (2) adding in the third sentence the phrase “and, provided further that, if no quotations can be obtained, then the Secured Party’s original calculation shall be used” immediately after the words “then that quotation shall be used” and before the “)”.

I.

Paragraph 9. Covenants; Representations and Warranties; Miscellaneous. Section 9(d) is amended by deleting (i) the parenthetical phrase at the end of the first sentence, which reads, “(including, without limitation costs and reasonable fees and disbursements of counsel)” and (ii) the entire second sentence.

J.

Schedule 1 to Collateral Annex: Schedule 1 to the Collateral Annex is deleted in its entirety.

IN WITNESS WHEREOF, the Parties have caused this Paragraph 10 to the Transition Collateral Annex to be duly executed as of the Effective Date of the Agreement.October 15, 2012. Party A: SYCAMORE COGENERATION COMPANY

Party B: SOUTHERN CALIFORNIA EDISON COMPANY

By:

By:

Name: Neil Burgess

Name: Marc L. Ulrich

Title:

Title:

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

99

Document comparison by Workshare Professional on Thursday, October 11, 2012 5:15:24 PM Input: Document 1 ID Description

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Description Rendering set

file://J:\RAP Contract Origination\2011 CHP\03_Issue Package\Attachment D-2 - EEI Paragraph 10\Attachment D-2 - EEI_Para10_Coll_Annex.doc Attachment D-2 - EEI_Para10_Coll_Annex file://J:\RAP Contract Origination\CHP Program\Contract Application Forms\Transition Contract Applications\2801 & 2058 - KRCC & Sycamore\Subsequent PPAs\Sycamore Subsequent PPA\Internal Drafts\20121011\20121011 Sycamore Transition Para 10.DOCX 20121011 Sycamore Transition Para 10 standard

Legend: Insertion Deletion Moved from Moved to Style change Format change Moved deletion Inserted cell Deleted cell Moved cell Split/Merged cell Padding cell Statistics: Count Insertions Deletions Moved from Moved to Style change Format changed

56 27 0 0 0 0

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83

2012 CHP RA Capacity

MASTER POWER PURCHASE AND SALE AGREEMENT CONFIRMATION LETTER BETWEEN [COUNTERPARTY(SELLER)]SYCAMORE COGENERATION COMPANY AND SOUTHERN CALIFORNIA EDISON COMPANY This confirmation letter ("“Confirmation"”) confirms the Transaction between [Counterparty]Sycamore Cogeneration Company (“Seller” or “Sycamore”) and Southern California Edison Company (“Buyer” or “SCE”), each individually a “Party” and together the “Parties”, dated as of [Date]October 15, 2012, (the "“Confirmation Effective Date"”) in which Seller agrees to provide to Buyer the right to the Product, as such term is defined in Article 2 of this Confirmation. This Transaction is governed by the Edison Electric Institute Master Power Purchase and Sale Agreement between the Parties, effective as of [Date],October 15, 2012, along with the Cover Sheet (the “Transition Cover Sheet:”), any amendments and annexes thereto (the "“Transition Master Agreement"”), and including, Paragraph 10 of the EEI Collateral Annex to the Transition Master Agreement (Paragraph 10 and the Collateral Annex are both referred to herein as the “Transition Collateral Annex”) (the Transition Master Agreement and the Transition Collateral Annex shall be collectively referred to as the “Transition EEI Agreement”). The Transition EEI Agreement and this Confirmation shall be collectively referred to herein as the “Agreement”. Capitalized terms used but not otherwise defined in this Confirmation have the meanings ascribed to them in the Transition EEI Agreement, or the Tariff (defined herein below). RECITALS A.

Seller owns and operates Generating Unit # 2 and Generating Unit # 4, and desires to sell the Product to Buyer pursuant to the terms and conditions set forth in this Agreement;

B.

Buyer is willing to purchase the Product from Seller pursuant to the terms and conditions set forth in the Agreement; and

C.

Concurrently with the execution hereof, as an inducement to enter into the Agreement, Buyer and Seller are entering into the Transition Tolling Confirmation and the Transition PPA.

ARTICLE 1 DEFINITIONS 1.1 “Applicable Laws"” means any law, rule, regulation, order, decision, judgment, or other legal or regulatory determination by any Governmental Body having jurisdiction over one or both Parties or this Transaction, including without limitation, the Tariff. 1.2

“Availability Incentive Payments” has the meaning set forth in the Tariff.

1.3

“Availability Standards” has the meaning set forth in the Tariff.

“Buyer" has the meaning specified in the introductory paragraph hereof. 1.4 “CAISO"” means the California Independent System Operator or any successor entity performing the same functions. “Capacity Attributes” means, with respect to a Generating Unit, any and all of the following, in each case which are attributed to or associated with the Generating Unit at any time throughout the Delivery Period: (a)

resource adequacy attributes, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward RAR;

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2012 CHP RA Capacity

1.6

(b)

resource adequacy attributes or other locational attributes for the Generating Unit related to a Local Capacity Area, as may be identified from time to time by the CPUC, CAISO or other Governmental Body having jurisdiction, associated with the physical location or point of electrical interconnection of the Generating Unit within the CAISO Control Area, that can be counted toward a Local RAR;

(c)

flexible capacity resource adequacy attributes for the Generating Unit, as may be identified from time to time by the CPUC, CAISO, or other Governmental Body having jurisdiction, that can be counted toward Flexible RAR; and

(d)

1.5 “Capacity Attributes” means any and allother current or future defined characteristics including flexibility, certificates, tags, credits, or accounting constructs, howsoever entitled, including any accounting construct counted toward any resource adequacy requirements, attributed to or associated with the Units throughout the Delivery PeriodRAR, Local RAR or Flexible RAR.

“Capacity Flat Price"” means the price specified in the Capacity Flat Price Table in Section 4.1.

1.7 “Capacity Replacement Price"” means the market price for the quantity of Product not provided by Seller under this Confirmation as determined in the manner upon which market prices are determined under Section 5.2(b) of the Transition Master Agreement. For purposes of Section 1.51 of the Transition Master Agreement, “Capacity Replacement Price” shall be deemed the “Replacement Price” for this Transaction. 1.8

“CHP” has the meaning set forth in Section 8.3.

“Confirmation” has the meaning specified in the introductory paragraph hereof. “Confirmation Effective Date” has the meaning specified in the introductory paragraph hereof. “Contingent Firm RA Product" has the meaning specified in Section 2.3 hereof. 1.9 “Contract Price"” means, for any Showing Month, the product of the Capacity Flat Price and the Price Shape for such period. 1.10 “Contract Quantity"” has the meaning set forth in Section 2.5.2.5 and means the total Unit Quantity for all Generating Units. 1.11 “CPUC Approval” means either (1) a final and non-appealable order of the CPUC, without conditions or modifications unacceptable to the Parties, or either of them, or (2) a final and nonappealable disposition of the CPUC’s Energy Division, without conditions or modifications unacceptable to the Parties, or either of them, which deems approved an advice letter requesting approval of each of this Confirmation and, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA in their respective entirety, including payments to be made by SCEBuyer, subject to CPUC review of SCEBuyer’s administration of each of this Confirmation and, the Transition Tolling Confirmation, the Transition Master Agreement, and the Transition PPA. CPUC Approval will be deemed to have occurred on the date that a CPUC decision or resolution, as the case may be, containing such findings becomes final and non-appealable. 1.12 “CPUC Decisions"” means CPUC Decisions 04-01-050, 04-10-035, 05-10-042, 06-04-040, 06-06064, 06-07-031, 07-06-029, 08-06-031, 09-06-028, 10-06-036036, 11-06-022, 12-06-025, and any other existing or subsequent decisions, resolutions, or rulings related to resource adequacy, including, without limitation, the CPUC Filing Guide, in each case as may be amended from time to time by the CPUC. 1.13 “CPUC Filing Guide” is the annual document issued by the CPUC which sets forth the guidelines, requirements and instructions for LSE’s to demonstrate compliance with the CPUC’s RA program. 1.14

"Delivery Period" has the meaning specified in Section 2.4.

1.15 “Exempt Wholesale Generator” means an unregulated power generator that is allowed to sell wholesale power s an independent energy producer, and is exempt from the Public Utility Holding Company Act of 1935.Delivery Period” has the meaning specified in Section 2.4. “Delivery Period End Date” has the meaning specified in Section 2.4.

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2012 CHP RA Capacity

“FERC Approval” means an order of the FERC that is final and no longer subject to appeal, which grants the Parties’ request that Buyer and Seller be permitted to engage in a power sale transaction at marketbased rates as such request is submitted to FERC by the Parties in accordance with Section 2.7 of the Transition Cover Sheet in full and in the form presented on terms and conditions acceptable to the Parties in their sole discretion. A FERC order granting the Parties’ request to engage in a power sale transaction at market-based rates will be deemed final and no longer subject to appeal if (i) no intervention in opposition to the submission made by the Parties is filed within the initial comment period; or (ii) if such an intervention in opposition is filed, no request for rehearing is filed within 30 days from the FERC order. At any time after a FERC order is issued granting the Parties’ request to engage in a power sale transaction at market-based rates, Seller and Buyer may jointly agree to waive the above requirement that such FERC order be final and no longer subject to appeal. “Firm RA Product" has the meaning specified in the Section 2.2 hereof. “Flexible RAR” means the flexible capacity requirements, including, without limitation, maximum continuous ramping, load following, and regulation, established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Flexible RAR may also be known as ramping, maximum ramping, maximum continuous ramping, maximum continuous ramping capacity, maximum continuous ramping ramp rate, load following, load following capacity, load following ramp rate, regulation, regulation capacity, and/or regulation ramp rate. “Flexible RAR Showings” means the Flexible RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. 1.16

“GADS"” means the Generating Availability Data System, or its successor.

1.17 “Generating Facility” means the power plants or other facilities where electricity is produced as described on the NERC website under “Reliability Terminology”. The For purposes of this Confirmation, the Generating Facility shall include the Units.Generating Unit # 2 and Generating Unit # 4 for the Delivery Period set forth in Section 2.4. “Generating Unit” or “Generating Units” shall mean the generation assets described in Appendix A (including any Replacement Units), from which Product is provided by Seller to Buyer. Unless otherwise stated in this Confirmation, references to Generating Unit or Generating Units shall be applicable only to Generating Until # 2 and Generating Unit #4 throughout the Delivery Period. “Generating Unit # 2” means the Generating Unit described in Appendix A(a). “Generating Unit # 4” means the Generating Unit described in Appendix A(c). 1.18 “Governmental Body"” means any federal, state, local, municipal or other government; any governmental, regulatory or administrative agency, commission or other authority lawfully exercising or entitled to exercise any administrative, executive, judicial, legislative, police, regulatory or taxing authority or power; and any court or governmental tribunal. 1.19

“Local Capacity Area” has the meaning set forth in the Tariff.

1.20

"Local RA Attributes" means, with respect to a Unit, any and all resource adequacy attributes or other locational attributes for the Unit related to a Local Capacity Area, as may be identified from time to time by the CPUC, CAISO or other Governmental Body having jurisdiction, associated with the physical location or point of electrical interconnection of the Unit within the CAISO Control Area, that can be counted toward a Local RAR, but exclusive of any RA Attributes.

1.21 “Local RAR"” means the local resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. Local RAR may also be known as local area reliability, local resource adequacy, local resource adequacy procurement requirements, or local capacity requirement in other regulatory proceedings or legislative actions.

3

2012 CHP RA Capacity

1.22 “Local RAR Showings"” means the Local RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and, to the extent authorized by the CPUC, to the CAISO) pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. 1.23

“LSE"” means load-serving entity.

“Monthly Delivery Period” means each calendar month during the Delivery Period and shall correspond to each Showing Month. 1.24

“Monthly Payment"” has the meaning specified in Section 4.1.

1.25

“NERC"” means the North American Electric Reliability Corporation, or its successor.

1.26 “NERC/GADS Protocols"” means the GADS protocols established by NERC, as may be updated from time to time. 1.27

“Net Qualifying Capacity” has the meaning set forth in the Tariff.

1.28

“Non-Availability Charges” has the meaning set forth in the Tariff.

1.29 “Outage"” means any disconnection, separation or reduction in the capacity of any Generating Unit, other than a Planned Outage but including, without limitation, any such disconnection, separation or reduction in capacity that is designated as either forced or unplanned pursuant to the Tariff or the NERC/GADS Protocols. “Outage Schedule” has the meaning specified in Section 7.1. 1.30 “Planned Outage" means, subject to and as further described in the CPUC Decisions, a CAISOapproved planned or scheduled disconnection, separation or reduction in capacity of any Unit that is conducted for the purposes of carrying out routine repair or maintenance of such Unit, or for the purposes of new construction work for such Unit. ” means an Approved Maintenance Outage (as defined in the Tariff), but does not include a RA Maintenance Outage with Replacement (as defined in the Tariff), a Short-Notice Opportunity RA Maintenance Outage (as defined in the Tariff) or an Off-Peak Opportunity RA Maintenance Outage (as defined in the Tariff). 1.31 “Power Rating” means the electrical power output value indicated on the generating equipment nameplate. 1.32

"Price Shape" means the Price Shape specified in the Monthly Payment Price Shape Table in Section 4.1.

1.33

"Product" has the meaning specified in Section 2.1.

“Product” means the Capacity Attributes of the Generating Unit, provided that: (a)

Product does not include any right to the energy or ancillary services from the Generating Units;

(b)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Local Capacity Areas that results in a decrease or increase in the amount of Capacity Attributes related to a Local Capacity Area provided hereunder will not result in a change in payments made pursuant to this Transaction;

(c)

any change by the CAISO, CPUC or other Governmental Body that defines new or redefines existing Flexible RAR, Capacity Attributes related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR, that results in a decrease or increase in the amount of Capacity Attributes related to Flexible RAR provided hereunder will not result in a change in payments made pursuant to this Transaction;

(d)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Local Capacity Areas whereby the a Generating Unit subsequently qualifies for a Local Capacity Area, the Product shall include all Capacity Attributes related to such Local Capacity Area; and

4

2012 CHP RA Capacity

(e)

the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Flexible RAR, Capacity Attributes related to Flexible RAR, or attributes of the Generating Units related to Flexible RAR whereby the a Generating Unit subsequently qualifies for to satisfy Flexible RAR, the Product shall include all Capacity Attributes related to Flexible RAR.

1.34 “PURPA” means the Public Utility Regulatory Policies Act of 1978, Public Law, 95 617, as amended from time to time. 1.35 “Qualifying Facility” means an electric generating facility that complies with the qualifying facility definition established by PURPA and any FERC rules as amended from time to time (18 CFR Part 292 Section 292.203 et seq.) implementing PURPA and has filed with FERC (i) an application for FERC certification, pursuant to 18 CFR 292.207(b)(1), which FERC has granted, or (ii) a notice of selfcertification pursuant to 18 CFR Part 292.207(a). 1.36

"RA Attributes" means, with respect to a Unit, any and all resource adequacy attributes, as may be identified from time to time by the CPUC, or other Governmental Body having jurisdiction, that can be counted toward RAR, exclusive of any Local RA Attributes.

1.37 “RAR"” means the resource adequacy requirements established for LSEs by the CPUC pursuant to the CPUC Decisions, the CAISO pursuant to the Tariff, or by any other Governmental Body having jurisdiction. 1.38 “RAR Showings"” means the RAR compliance showings (or similar or successor showings) an LSE is required to make to the CPUC (and/or, to the extent authorized by the CPUC, to the CAISO), pursuant to the CPUC Decisions, to the CAISO pursuant to the Tariff, or to any Governmental Body having jurisdiction. 1.39

“Replacement Capacity"” has the meaning specified in Section 5.2.

1.40

“Replacement Unit"” means a generating unit meeting the requirements specified in Section 5.1.

1.41 “Resource Category"” shall be as described in the annual CPUC Filing Guide, as such may be modified, amended, supplemented or updated from time to time. “Resource ID” has the meaning set forth in the Tariff. “RFO Agreement” means the Master Power Purchase and Sale Confirmation Letter (RA Capacity) between the Parties, dated July 2, 2012, as may be amended from time to time. 1.42

“Scheduling Coordinator” or “SC” has the meaning set forth in the Tariff.

1.43 “Settlement Agreement” means the Qualifying Facility and Combined Heat and Power Program Settlement Agreement, approved by the CPUC in Decision 10-12-035 issued on December 21, 2010.2010, effective November 23, 2011. “Seller” has the meaning specified in the introductory paragraph hereof. “Shortfall Capacity” has the meaning set forth in Section 3.4. 1.44 “Showing Month” shall be the calendar month of the Delivery Period that is the subject of the RAR Showing, Local RAR Showing or Flexible RAR Showing, in each case, as set forth in the CPUC Decisions and outlined in the Tariff. For illustrative purposes only, pursuant to the Tariff and CPUC Decisions in effect as of the Confirmation Effective Date, the monthly RAR Showing made in June is for the Showing Month of August. 1.45

“Substitute Capacity” has the meaning set forth in Section 10.1.

1.46

“Substitution Rules” has the meaning set forth in Section 10.2.

1.47

“Supply Plan"” has the meaning set forth in the Tariff.

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2012 CHP RA Capacity

1.48 “Tariff"” means the tariff and protocol provisions, including any current CAISO-published “Operating Procedures” and “Business Practice Manuals,” as amended or supplemented from time to time, of the CAISO. 1.49 “Term” shall have the following meaning: The “Term” of this Transaction shall commence upon the Confirmation Effective Date and shall continue until the later of (a) the expiration of the Delivery Period or (b) the date the Parties’ obligations under this Agreement have been satisfied. 1.50

“Transition Agreement” has the meaning specified in the introductory paragraph hereof.

“Transition Collateral Annex” has the meaning specified in the introductory paragraph hereof. “Transition Cover Sheet” has the meaning specified in the introductory paragraph hereof. “Transition Master Agreement” has the meaning specified in the introductory paragraph hereof. “Transition PPA” has the meaning set forth in the Transition Cover Sheet. “Transition Tolling Confirmation” means that certain Tolling Confirmation of even date herewith between Seller and SCEBuyer, which will be submitted for CPUC Approval together with this Confirmation pursuant to the same advice letter filing. 1.51

"Unit" or "Units" shall mean the generation assets described in Appendix A (including any Replacement Units), from which Product is provided by Seller to Buyer.

1.52 “Unit NQC” means the Net Qualifying Capacity set by the CAISO for the applicable Generating Unit. The Parties agree that if the CAISO adjusts the Net Qualifying Capacity of a Generating Unit after the Confirmation Effective Date, that for the period in which the adjustment is effective, the Unit NQC shall be deemed the lesser of (i) the Unit NQC as of the Confirmation Effective Date, or (ii) the CAISOadjusted Net Qualifying Capacity. 1.53 “Unit Quantity"” means the amount of Product (in MWs) provided by Seller to Buyer by each individual Generating Unit identified in Appendix ASection 2.5 during the portions of the Delivery Period the Generating Unit is subject to the obligations of this Confirmation and subject to reductions as outlined in Section 3.2.

ARTICLE 2 TRANSACTION 2.1

Product[Intentionally omitted]

The RA Attributes, Local RA Attributes and Capacity Attributes of the Unit(s) identified in Appendix A (collectively, the “Product”). Product does not include any right to the energy or ancillary services from the Unit. Any change by the CAISO, CPUC or other Governmental Body that defines new or re-defines existing Local Capacity Areas that result in a decrease or increase in the amount of Local RA Attributes provided hereunder will not result in a change in payments made pursuant to this Transaction. In addition, the Parties agree that, under this Confirmation, if the CAISO, CPUC or other Governmental Body defines new or re-defines existing Local Capacity Areas whereby the Units qualify for a Local Capacity Area, the Product shall include such Local RA Attributes. 2.2

Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity. for each day of each month of the Delivery Period If the Generating Units are not available to provide the full amount of the Contract Quantity for each day of a Showing Month for any reason, including without limitation any Outage or Planned Outage or any adjustment of the RA Attributes, Local RA Attributes and Capacity Attributes of any Generating Unit, Seller shall provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1 hereof. If Seller

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2012 CHP RA Capacity

fails to provide Buyer with Replacement Capacity from Replacement Units pursuant to Section 5.1, then Seller shall be liable for damages and/or to indemnify Buyer for penalties or fines pursuant to the terms of Article Five. The Parties agree that Section 3.2 shall not apply if this Section 2.2 has been elected. 2.3

Contingent Firm RA Product

Seller shall provide Buyer with the Product from the Generating Units in the amount of the applicable Contract Quantity for each day of each month of the Delivery Period. If the Generating Units are not available to provide the full amount of the Contract Quantity for each day of a Showing Month, Seller may elect to provide Buyer with Replacement Capacity from one or more Replacement Units pursuant to Section 5.1. In such case, if Seller elects to provide Replacement Capacity pursuant to Section 5.1 and fails or if Seller elects not to provide such Replacement Capacity, then Seller shall be liable for damages and/or shall indemnify Buyer for penalties or fines pursuant to the terms of Article Five. If the Generating Units provide less than the full amount of the Contract Quantity in the event of a Planned Outage or a reduction to Unit NQC, Seller is not obligated to provide Buyer with Replacement Capacity and shall not be liable for damages or obligated to indemnify Buyer for penalties or fines pursuant to Article 5 hereof. Notwithstanding anything to the contrary set forth in this Confirmation, Seller has no obligation to deliver, and Buyer has no obligation to make a Monthly Payment for the Product for the Monthly Delivery Period if the Showing Month for the applicable month occurred before CPUC Approval. 2.4

Delivery Period

The Delivery Period shall be: [Start Date] through [End Date], inclusive, unless terminated earlier in accordance with the terms of this Agreement; provided, however, that: (i) before“Delivery Period” shall be: the later of (a) October 15, 2012, or (b) the date when this Agreement has received both CPUC Approval and FERC Approval; provided, however, notwithstanding anything to the contrary set forth in this Agreement, the Delivery Period shall not commence until all of the condition precedents set forth in the Transition Tolling Confirmation and the Transition PPA have been satisfied or waived in accordance with the terms and conditions thereof (subject to any extension of the Delivery Period start date pursuant to Section 11.2.1 of the Settlement Agreement or as a result of a Force Majeure as to which Seller is the Claiming Party (subject to Section 5.03 of the Transition PPA)), through, unless terminated earlier in accordance with the terms of this Agreement, the date that is immediately prior to the commencement of the Delivery Period, SCE must have obtained or waived CPUC Approval and (ii) the Delivery Period must commence within 24 months of the Confirmation Effective Date. ‘Delivery Period’ under and as defined in the RFO Agreement, which shall be no later than June 30, 2014 (the “Delivery Period End Date”); provided, however if ‘CPUC Approval’ (as defined in the RFO Agreement) and/or ‘FERC Approval’ (as defined in the RFO Agreement) of the RFO Agreement are not obtained prior to June 30, 2014, through no fault of Seller, then the Delivery Period End Date shall be June 30, 2015.

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2012 CHP RA Capacity

2.5

Contract Quantity

The Contract Quantity equals the total sum of each Unit Quantity identified in Appendix A. As of the Confirmation Effective Date, the Contract Quantityfor each day of each applicable Showing Month is as follows: Contract Quantity (MWs) Showing Month

2012

2013

2014

2015

8

2012 CHP RA Capacity

Generating Unit # 2 Contract Quantity (MWs) Showing Month

2012

Generating Unit # 4 Contract Quantity (MWs)

2013

2014

2015

January

74

74

74

February

74

74

March

74

April

Showing Month

2012

2013

2014

2015

January

74

74

74

74

February

74

74

74

74

74

March

74

74

74

74

74

74

April

74

74

74

May

74

74

74

May

74

74

74

June

74

74

74

June

74

74

74

July

74

74

July

74

74

August

74

74

August

74

74

September

74

74

September

74

74

October

74

74

74

October

74

74

74

November

74

74

74

November

74

74

74

December

74

74

74

December

74

74

74

ARTICLE 3 DELIVERY OBLIGATIONS 3.1

Delivery of Product

Subject to any reductions set forth in Section 3.2 (if Section 2.3 above is selected), Seller shall provide Buyer with the Contract Quantity of Product for each day of each Showing Month consistent with the following: (a)

Seller shall, on a timely basis, submit, or cause each Generating Unit's SC to submit, Supply Plans in accordance with the Tariff to identify and confirm the Unit Quantity provided to Buyer for each day of each Showing Month so that the total amount of Unit Quantity identified and confirmed for each day of such Showing Month equals the Contract Quantity for such day of such Showing Month, unless specifically requested not to do so by the Buyer.

(b)

Seller shall cause each Generating Unit’s SC to submit written notification to Buyer, no later than fifteen (15) Business Days before the relevant deadline for any applicable RAR orShowing, Local RAR Showing or Flexible RAR Showing, that Buyer will be credited with the Unit Quantity for each day of the Delivery PeriodShowing Month in the Generating Unit’s SC Supply Plan so that the total amount of Unit Quantity for each day of such Showing Month credited equals the Contract Quantity.

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2012 CHP RA Capacity

3.2

Adjustments to Contract Quantity

In the event that Section 2.3 is applicable, then: (a)

Seller’s obligation to deliver the Contract Quantity of Product for anyeach day of each Showing Month may be reduced if any portion of the Generating Unit(s) is scheduled for a Planned Outage during that month for the applicable days of such Planned Outage; provided, Seller notifies Buyer, no later than fifteen (15) Business Days before the relevant deadline for the corresponding RAR Showing or, Local RAR Showing or Flexible RAR Showing applicable to that monthShowing Month, the amount of Product from each Generating Unit Buyer is permitted to include in Buyer’s RAR orShowing, Local RAR Showing or Flexible RAR Showing applicable to that month as a result of such Planned Outage. In the event Seller is unable to provide the Contract Quantity of Productfor any portion of a Showing Month because of a Planned Outage of a Generating Unit, Seller has the option, but not the obligation, to provide Product from Replacement Units; provided, Seller provides and identifies such Replacement Units consistent with Section 5.1. In addition, if Seller chooses not to provide Product from Replacement Units and a Generating Unit is on a Planned Outage for any portion of the applicable Showing Month, then, the Contract Quantity shall be revised in accordance with any applicable adjustments stipulated by the CPUC Filing Guide or CAISO guidelines in effect for the applicable portion of the Showing Month in which the Planned Outage occurs.

(b)

3.3

(b) Reductions in Unit NQC: In the event the Generating Unit experiences a reduction in Unit NQC as determined by the CAISO; Seller has the option, but not the obligation, to provide the Unit Quantity from the same Generating Unit; provided the Generating Unit has sufficient remaining and available Product.

Buyer’s Re-Sale of Product

Buyer may re-sell all or a portion of the Product acquired hereunder. 3.4

Post-Showing Replacement Capacity

In the event CAISO determines, in accordance with the Tariff, that any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any portion of a Showing Month which was shown by Buyer in its RAR Showings, Local RAR Showings or Flexible RAR Showings requires outage replacement in accordance with Section 40.7 of the Tariff (“Shortfall Capacity”), (i) Seller’s Monthly Payment will be reduced in accordance with Section 4.1 below and, neither Seller, nor the Generating Unit’s SC (unless the Generating Unit’s SC is Buyer), shall have the right to provide Buyer with RA Replacement Capacity with respect to such Shortfall Capacity, (ii) Seller shall have no liability under Sections 5.2 or 5.3 below with respect to such Shortfall Capacity, except to the extent described in Section 10.3 below and (iii) Seller shall have no liability to Buyer for any costs which are allocated to Buyer by the CAISO for any RA Maintenance Outage Backstop Capacity procured by CAISO which was related to such Shortfall Capacity, except to the extent described in Section 10.3 below. Notwithstanding anything to the contrary in this Agreement, at any time that any of the proposed amendments to the Tariff relating to outage replacement, filed by the CAISO at FERC on September 20, 2012 (Docket ER 12-2669-000), have not been authorized by FERC, the provisions of this Section 3.4 shall not be applicable, and, for purposes of calculating Seller’s Monthly Payment under Section 4.1, “D” (Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month) shall equal zero.

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2012 CHP RA Capacity

ARTICLE 4 PAYMENT 4.1

Monthly Payment

In accordance with the terms of Article Six of the Transition Master Agreement, Buyer shall make a Monthly Payment to Seller for each Generating Unit, after the applicable Showing Month, as follows:

Monthly Payment = (A x B x 1,000) where: A = applicable Contract Price for that Showing Month B = Unit C = Contract Quantity provided by Seller to Buyer pursuant to and consistent with Section 3.1 for the applicable day of the Showing Month D = Aggregate megawatts of Shortfall Capacity associated with the applicable day of the Showing Month i = Each day of Showing Month n = number of days in the Showing Month The Monthly Payment calculation shall be rounded to two decimal places. CAPACITY FLAT PRICE TABLE Contract Year

RA Capacity Flat Price ($/kW-month)

2012

1.18

2013

1.18

2014

1.18

2015

1.18

The respective monthly Price Shape, set forth in the Monthly Payment Price Shape Table below, shall apply throughout the entire Delivery Period.

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2012 CHP RA Capacity

MONTHLY PAYMENT PRICE SHAPE TABLE

4.2

Showing Month

Price Shape (%)

Jan

[ ]10%

Feb

[ ]5%

Mar

[ ]5%

Apr

[ ]5%

May

[ ]15%

Jun

[ ]40%

Jul

[ ]365%

Aug

[ ]490%

Sep

[ ]205%

Oct

[ ]25%

Nov

[ ]15%

Dec

[ ]20%

Allocation of Other Payments and Costs (a)

Seller shall retain any revenues it may receive from and pay all costs charged by the CAISO or any other third party with respect to any Generating Unit for (i) start-up, shutdown, and minimum load costs, (ii) capacity revenue for ancillary services, (iii) energy sales, and (iv) any revenues for black start or reactive power services.

(b)

Buyer shall be entitled to receive and retain all revenues associated with the Contract Quantity of Product during the Delivery Period (including any capacity revenues from RMR Contracts for any Generating Unit, Capacity Procurement Mechanism (CPM), or its successor, and Residual Unit Commitment (RUC) Availability Payments, or its successor, but excluding payments described in Section 4.2(a)(i)-(iv) above).

(c)

In accordance with Section 4.1 of this Confirmation and Article Six of the Transition Master Agreement, (i) all such Buyer revenues described in this Section 4.2, but received by Seller, or a Generating Unit’s SC, owner, or operator shall be remitted to Buyer, and Seller shall pay such revenues to Buyer if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Buyer. If Seller fails to pay such revenues to Buyer, Buyer may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts itBuyer may owe to Seller under this Confirmation. In order to verify the accuracy of such revenues, Buyer shall have the right, at its sole expense and during normal working hours after reasonable prior notice, to hire an independent third party reasonably acceptable to Seller to audit any documents, records or data of Seller associated with the Contract Quantity; and

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2012 CHP RA Capacity

(ii) all such Seller, or a Generating Unit’s SC, owner, or operator revenues described in this Section 4.2, but received by Buyer shall be remitted to Seller, and Buyer shall pay such revenues to Seller if the Generating Unit’s SC, owner, or operator fails to remit those revenues to Seller. If Buyer fails to pay such revenues to Seller, Seller may offset any amounts owing to it for such revenues pursuant to Article Six of the Transition Master Agreement against any future amounts it may owe to Buyer under this Confirmation. (d)

If a centralized capacity market develops within the CAISO region, Buyer will have exclusive rights to offer, bid, or otherwise submit the Contract Quantity provided to Buyer pursuant to this Confirmation for re-sale in such market, and retain and receive any and all related revenues.

(e)

Seller agrees that the Unit isGenerating Units are subject to the terms of the Availability Standards, Non-Availability Charges, and Availability Incentive Payments as contemplated under Section 40.9 of the Tariff. Furthermore, the Parties agree that any Availability Incentive Payments are for the benefit of the Seller and for Seller’s account and that any Non-Availability Charges are the responsibility of the Seller and for Seller’s account.

ARTICLE 5 SELLER'S FAILURE TO DELIVER CONTRACT QUANTITY 5.1

Seller’s Duty To Provide Replacement Capacity

Subject to any adjustments made pursuant to Section 3.2(a) (if Section 2.3 above is selected), if Seller is unable to provide the full Contract Quantity of Product for day of any Showing Month, then:

5.2

(a)

Seller may, at no cost to Buyer, provide Buyer with replacement Product from one or more Replacement Units, such that the total amount of Product provided to Buyer from all Generating Units and Replacement Units for each day of the Showing Month equals the Contract Quantity; provided, that (i) replacement Product from any generating unit other than the generating units described in Section 5.1(a)(ii) may only be provided with Buyer’s consent, which may not be unreasonably or untimely withheld, and (ii) replacement Product from any of Seller’s generating units subject to the Transition PPA may only be provided with Buyer’s consent, which Buyer may give or withhold in Buyer’s sole discretion; and

(b)

Seller shall identify Replacement Units meeting the above requirements no later than fifteen (15) Business Days before the relevant deadline for Buyer's RAR Showing and/or Local RAR Showing.

(b)

Seller shall identify Replacement Units meeting the above requirements no later than fifteen (15) Business Days before the relevant deadline for Buyer's RAR Showing, Local RAR Showing and/or Flexible RAR Showing, provided, that the designation of any Replacement Unit by Seller shall be subject to Buyer’s prior written approval, which shall not be unreasonably withheld. Once Seller has identified in writing any Replacement Units that meet the requirements of this Section 5.1, any such Replacement Unit shall be automatically deemed a Generating Unit for purposes of this Confirmation for that Showing Month.

Damages for Failure to Provide Replacement Capacity

If either Section 2.2 or 2.3 is selected above and Seller fails to provide Buyer any portion of the Contract Quantity (as adjusted pursuant to Section 3.2) for any day of any Showing Month or if Seller has elected to provide replacement Product in accordance with the terms of this Confirmation, but fails to provide

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2012 CHP RA Capacity

such replacement Product from one or more Replacement Units for any Showing Month, then, in each case, the following shall apply:

5.3

(a)

Buyer may, but shall not be required to, replace any portion of the Contract Quantity not provided by Seller for any portions of each Showing Month with capacity having equivalent RA and Local RACapacity Attributes as the Product not provided by Seller ("“Replacement Capacity"”). Buyer may enter into purchase transactions with one or more parties to replace the portion of Contract Quantity not provided by Seller for all portions of each Showing Month. Additionally, Buyer may enter into one or more arrangements to repurchase its obligation to sell and deliver the capacity to another party, and such arrangements shall be considered the procurement of Replacement Capacity. Buyer shall act in a commercially reasonable manner in procuring any Replacement Capacity.

(b)

Seller shall pay to Buyer at the time set forth in Section 4.1 of the Transition Master Agreement, the following damages in lieu of damages specified in Section 4.1 of the Transition Master Agreement: an amount equal to the positive difference, if any, between (i) the sum of (A) the actual cost paid by Buyer for any Replacement Capacity, including any transaction costs and expenses incurred in connection with such procurement, plus (B) each Capacity Replacement Price times the aggregate amount of the Contract Quantity neither provided by Seller nor purchased by Buyer for all portions of the applicable Showing Month pursuant to Section 5.2(a), and (ii) the aggregate amount of Contract Quantity not provided for all applicable portions of the applicable Showing Month times the Contract Price for that month. If Seller fails to pay these damages, then Buyer may offset those damages owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement.

Indemnities for Failure to Deliver Contract Quantity

Subject to any adjustments made pursuant to Section 3.2(a), Seller agrees to indemnify, defend and hold harmless Buyer from any penalties, fines or costs assessed against Buyer by the CPUC or the CAISO, resulting from any of the following: (a)

Seller’s failure to provide any portion of the Contract Quantity, if Seller fails to replace the shortfall in Contract Quantity from Replacement Units in accordance with Section 5.1 for any portion of the Delivery Period;

(b)

Seller’s failure to provide notice of the non-availability of any portion of the Contract Quantity for any portion of the Delivery Period as required under Section 3.1; or

(c)

A Generating Unit’s SC’s failure to timely submit Supply Plans that identify Buyer’s right to the Unit Quantity purchased hereunder for each day of the Delivery Period.

With respect to the foregoing, the Parties shall use commercially reasonable efforts to minimize such penalties, fines and costs; provided, that in no event shall Buyer be required to use or change its utilization of its owned or controlled assets or market positions to minimize these penalties and fines. Seller will have no obligation to Buyer under this Section 5.3 in respect of the portion of Contract Quantity for which Seller has paid damages for Replacement Capacity. If Seller fails to pay those penalties, fines or costs, or fails to reimburse Buyer for those penalties, fines or costs, then Buyer may offset those penalties, fines or costs against any future amounts it may owe to Seller under this Confirmation.

ARTICLE 6 CAISO OFFER REQUIREMENTS Subject to Buyer’s request under Section 10.1, during the Delivery Period, except to the extent any Generating Unit is in an Outage or Planned Outage, Seller shall either schedule or cause the Generating

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2012 CHP RA Capacity

Unit’s SC to schedule with, or make available to, the CAISO the Unit Quantity for each Generating Unit in compliance with the Tariff, and shall perform all, or cause the Generating Unit’s SC, owner, or operator, as applicable, to perform all obligations under the Tariff that are associated with the sale of Product hereunder. Buyer shall have no liability for the failure of Seller or the failure of any Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance, provided that Buyer in its capacity as SC shall remain liable for any failure by it to comply with such Tariff provisions, to the extent required by Applicable Laws.

ARTICLE 7 PLANNED OUTAGES Upon the Confirmation Effective Date, thirty (30) days before the applicable year-ahead showing, and no later than January 1, April 1, July 1 and October 1 of each calendar year thereafter until the end of the Term, Seller shall submit, or cause the Generating Unit's SC to submit to Buyer, the portion of each Generating Unit's schedule of proposed Planned Outages ("“Outage Schedule"”) for the following twelve (12) month period or until the end of the Delivery Period, whichever is shorter. Within twenty (20) Business Days after its receipt of an Outage Schedule, Buyer shall notify Seller in writing of any reasonable request for changes to the Outage Schedule, and Seller shall, consistent with Good Utility Practices, accommodate Buyer's requests regarding the timing of any Planned Outage. Seller or the Generating Unit's SC shall notify Buyer within five (5) Business Days of any change to the Outage Schedule.

ARTICLE 8 OTHER BUYER AND SELLER COVENANTS 8.1

Seller’s and Buyer’s Duty to Take Action to Allow the Utilization of the Product

Buyer and Seller shall, throughout the Delivery Period, take all commercially reasonable actions and execute any and all documents or instruments reasonably necessary to ensure Buyer's right to the use of the Contract Quantity for the sole benefit of Buyer's RAR and, Local RAR and Flexible RAR, if applicable. The Parties further agree to negotiate in good faith to make necessary amendments, if any, to this Confirmation to conform this Transaction to subsequent clarifications, revisions, or decisions rendered by the CPUC, FERC, CAISO or other Governmental Body having jurisdiction to administer RAR or, Local RAR or Flexible RAR, to maintain the benefits of the bargain struck by the Parties on the Confirmation Effective Date. As soon as possible, but no later than 30 days prior to the Delivery Period, Seller shall provide the Unit NQC and CAISO Resource ID for each of the Generating Units subject to the terms and conditions of this Confirmation. 8.2

Seller’s Represents, Warrants and Covenants

Seller represents, warrants and covenants to Buyer that, throughout the Delivery Period: and to the extent such Generating Unit is then subject to the obligations of this Confirmation: (a)

Seller owns or has the exclusive right to the Product sold under this Confirmation from each Generating Unit, and shall furnish Buyer, CAISO, CPUC or other Governmental Body with such evidence as may reasonably be requested to demonstrate such ownership or exclusive right;

(b)

No portion of the Contract Quantity has been committed by Seller to any third party in order to satisfy RAR or Local RAR or Flexible RAR or analogous obligations in any

15

2012 CHP RA Capacity

CAISO or non-CAISO markets, other than pursuant to an RMR Contract between the CAISO and either Seller or the Generating Unit’s owner or operator;

8.3

(c)

Each Generating Unit is connected to the CAISO Controlled Grid, is within the CAISO Control Area, and is under the control of CAISO;

(d)

Seller shall, and each Generating Unit’s SC, owner and operator is obligated to, comply with Applicable Laws, including the Tariff, relating to the Product;

(e)

If Seller is the owner of any Generating Unit, the aggregation of all amounts of Local RA Attributes and RACapacity Attributes that Seller has sold, assigned or transferred for any Generating Unit does not exceed the Unit NQC for that Generating Unit;

(f)

Seller has notified the SC of each Generating Unit that (i) Seller has transferred the Unit Quantity with respect to each day of each Showing Month to Buyer, and (ii) the SC is obligated to deliver the Supply Plans in accordance with the Tariff;

(g)

Seller has notified the SC of each Generating Unit that Seller is obligated to cause each Generating Unit’s SC to provide to the Buyer, at least fifteen (15) Business Days before the relevant deadline for each RAR orShowing, Local RAR Showing or Flexible RAR Showing, the Unit Quantity of each Unitfor each day of such Showing Month of each Generating Unit which is subject to the obligations of this Confirmation that is to be submitted in the Supply Plan associated with this AgreementConfirmation for the applicable period; and

(h)

Seller has notified each Generating Unit’s SC that (i) Buyer is entitled to the revenues set forth in Section 4.2,4.2 and (ii) such SC is obligated to promptly deliver those revenues to Buyer, along with appropriate documentation supporting the amount of those revenues.; and

(i)

Buyer shall have no liability for the failure of Seller or the failure of the Generating Unit’s SC, owner, or operator to comply with such Tariff provisions, including any penalties, charges or fines imposed on Seller or the Generating Unit’s SC, owner, or operator for such noncompliance.

Combined Heat and Power (“CHP”) Program Provisions; CPUC Approval; FERC Approval (a)

CHP Program Procurement and Seller Eligibility Seller and SCEBuyer acknowledge and agree that SCEBuyer is entering into this Confirmation pursuant to the Settlement Agreement and that the procurement made by SCEBuyer pursuant to this Confirmation is and shall be deemed by the Parties to be procurement under the CHP program as contemplated by the Settlement Agreement. Accordingly, Seller represents and warrants to SCE that (a) the Generating Facility met the PURPA efficiency requirements (18 Code of Federal Regulations, Part 292, Section 292.205) as of September 2007; (b)Buyer that as of the Confirmation Effective Date, the Power Rating of the Generating Facility equals [___] MW; and (c) as of the Confirmation Effective Date, the Generating Facility is a [Unit # 2 and Generating Unit # 4, together with the generating units that are subject to the obligations in the Transition PPA is a Qualifying Facility][Exempt Wholesale Generating Facility].Notwithstanding anything to the contrary set forth in this Agreement, Seller covenants that the Power Rating of the Generating Facility shall always exceed 5 MW..

(b)

CPUC Approval (i) Within 60 days after the Confirmation Effective Date, SCE shall file with the CPUC the appropriate request for CPUC Approval. SCE shall expeditiously seek CPUC Approval, including promptly responding to any requests for information related to the request for CPUC Approval. Seller shall use commercially reasonable efforts to support SCE in obtaining CPUC Approval. SCE has no obligation to seek rehearing or to appeal

16

2012 CHP RA Capacity

a CPUC decision which fails to approve this Transaction and this Confirmation or which contains findings required for CPUC Approval with conditions or modifications unacceptable to either Party. (ii) Either Party has the right to terminate this Transaction and this Confirmation on notice, which will be effective five Business Days after such notice is given, if CPUC Approval has not been obtained or waived by SCE in its sole discretion within 365 days after SCE files its request for CPUC Approval and a notice of termination is given on or before the 395th day after SCE files the request for CPUC Approval.(iii) Failure to obtain CPUC Approval in accordance with this Section 8.3(b) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of SCEBuyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain CPUC Approval. (c)

Provision of Information Seller shall deliver to SCE, on or before the 10th Business Day following receipt of a notice from SCE, such information that SCE is required to report to any authorized governmental authority pursuant to the Settlement Agreement, or which SCE otherwise requires in order to comply with the Settlement Agreement.

(d)

FERC Approval (i) Within 60 days of the Confirmation Effective Date, Buyer and Seller shall jointly file with the FERC the appropriate request for FERC Approval. The Parties shall seek the timely issuance by FERC of an order granting FERC Approval with respect to the transactions contemplated hereunder, including promptly responding to any requests for information related to the request for FERC Approval from the FERC. The Parties shall use reasonable efforts to support one another in obtaining FERC Approval. Neither Buyer nor Seller shall have an obligation to seek rehearing or to appeal a FERC decision that fails to grant Seller the authority to sell the Product to Buyer at the prices set forth in this Transaction and this Confirmation or contains findings, conditions or other terms required for FERC Approval that are unacceptable to either Party. If FERC Approval requires any material changes to this Agreement and the Parties, after negotiating in good faith, do not mutually agree to such changes within 30 calendar days after the FERC order, then this Transaction and this Confirmation will be subject to the dispute resolution provisions as provided in Section 10.6 of the Transition Master Agreement. Buyer shall make best efforts to provide Seller with a draft of the public version of the independent evaluator report with respect to the transactions contemplated hereby within 50 days after the Confirmation Effective Date; provided that if Buyer is unable to provide Seller with a draft of the public version of such independent evaluator report within 50 days after the Confirmation Effective Date, the date for the filing at FERC requesting FERC Approval set forth in this subsection (a) shall be deferred on a day-for-day basis for each day beyond the 50 days after the Confirmation Effective Date until Buyer provides Seller such independent evaluator report. (ii) Failure to obtain FERC Approval in accordance with this Section 8.3(d) will not be deemed to be a failure of Seller to sell or deliver the Product or a failure of Buyer to purchase or receive the Product, and will not be or cause an Event of Default by either Party. No Settlement Amount with respect to this Transaction will be due or owing by either Party upon termination of this Transaction and this Confirmation due solely to failure to obtain FERC Approval.

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2012 CHP RA Capacity

ARTICLE 9 CONFIDENTIALITY Notwithstanding Section 10.11 of the Transition Master Agreement, the Parties agree that Buyer may disclose the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to any Governmental Body, the CPUC, the CAISO in order to support its Local RAR orShowings, RAR Showings or Flexible RAR Showings, if applicable, and Seller may disclose the transfer of the Contract Quantity or any applicable portion of the Contract Quantity under this Transaction to the SC of each Generating Unit in order for such SC to timely submit accurate Supply Plans; provided, that each disclosing Party shall use reasonable efforts to limit, to the extent possible, the ability of any such applicable Governmental Body, CAISO, or SC to further disclose such information. In addition, in the event Buyer resells all or any portion of the Product to another party, Buyer shall be permitted to disclose to the other party to such resale transaction all such information necessary to effect such resale transaction.

ARTICLE 10 GENERATING UNIT SUBSTITUTION 10.1

Substitute Capacity

No later than five (5) Business Days before the relevant deadline for each RAR orShowing, Local RAR Showing or Flexible RAR Showing, Buyer may request that Seller not list, or cause each Generating Unit’s SC not to list, a portion or all of a Generating Unit’s Unit Quantity for any portion of a Showing Month on the Supply Plan. The amount of Unit Quantity that is the subject of such a request shall be known as “Substitute Capacity” and, for purposes of calculating a Monthly Payment pursuant to Section 4.1, be deemed Unit Quantity provided consistent with Section 3.1. Seller shall, or shall cause each Generating Unit’s SC to, comply with Buyer’s request under this Section 10.1. 10.2

Seller’s Obligations With Respect to Substitute Capacity

If Buyer makes a request for Substitute Capacity, Seller shall (a) make such Substitute Capacity available to Buyer during the applicable Showing Month in order to allow Buyer to utilize the substitution rules found in Section 40.9.4.2.1 of the Tariff (“Substitution Rules”); and (b) take all action, or cause each Generating Unit’s SC to take all action, to allow Buyer to utilize the Substitution Rules, including, but not limited to, ensuring that the Substitute Capacity will qualify for substitution under the Substitution Rules and providing Buyer with all information needed to utilize the Substitution Rules. Seller agrees that all Substitute Capacity that is utilized under the Substitution Rules is subject to the requirements identified in Article 6 as if the capacity had been included on the Supply Plan. 10.3

Failure to Provide Substitute Capacity

If Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitute Capacity under the Substitution Rules, then Seller shall pay for any and all Non-Availability Charges incurred by Buyer for such failure or inability to utilize the Substitution Rules; provided, that if Seller fails to provide Substitute Capacity or Buyer is unable to utilize the Substitution Rules, in each case, because the Substitute Capacity does not qualify for substitution under the last sentence of Section 40.9.4.2.1(1) of the Tariff or under the last sentence of Section 40.9.4.2.1(2) of the Tariff, then Seller shall not be responsible for any such Non-Availability Charges described in this Section 10.3 associated with such inability. If Seller fails to pay any Non-Availability Charges under this Section 10.3, then Buyer may offset those charges owed it against any future amounts it may owe to Seller under this Confirmation pursuant to Article Six of the Transition Master Agreement.

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10.4

Notwithstanding anything to the contrary in this Confirmation, Article 10 shall not apply to this Confirmation at any time during which Buyer is the SC.

ARTICLE 11 MARKET BASED RATE AUTHORITY Seller agrees, in accordance with FERC Order No. 697, to, upon request of Buyer, submit a letter of concurrence in support of any affirmative statement by Buyer that this contractual arrangement does not transfer “ownership or control of generation capacity” from Seller to Buyer as the term “ownership or control of generation capacity” is used in 18 CFR § 35.42. Seller also agrees that it will not, in any filings, if any, made subject to Order Nos. 652 and 697, claim that this contractual arrangement conveys ownership or control of generation capacity from Seller to Buyer.

ARTICLE 12 COLLATERAL REQUIREMENTS 12.1

Seller Collateral Requirements

Notwithstanding anything to the contrary contained in the Transition Master Agreement, Seller shall provide to, and maintain with, Buyer a Full Floating Independent Amount as long as Seller or its Guarantor, if any, does not maintain Credit Ratings of at least (a) BBB- from S&P, Baa3 from Moody’s, and BBB- from Fitch, if such entity is rated by the Ratings Agencies, (b) the lower of BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only two of the Ratings Agencies, or (c) BBB- by S&P, Baa3 by Moody’s, or BBB- by Fitch if such entity is rated by only one Ratings Agency. The Full Floating Independent Amount shall be equal to $ [________] [20% of the sum of the Monthly Payments for the current month and all remaining months of the Delivery Period, without the reductions specified in Section 3.2].3.2. For the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, such Full Floating Independent Amount for Seller shall be added to the Exposure Amount for Buyer and subtracted from the Exposure Amount for Seller. 12.2

Current Mark-to-Market Value

The Parties further agree that for the purposes of calculating the Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, the Current Mark-to-Market Value for this Transaction is deemed to be zero. If at any time prior to the expiration of the Delivery Period, a liquid market for an RA Capacity product develops wherein price quotes for such a product can be obtained, the Parties agree to amend the Confirmation to include a methodology for calculating the Current Mark-to-Market Value for this Transaction, consequently affecting the Buyer’s Exposure. 12.3

Credit Terms

The Parties agree that the credit and collateral provisions of the Transition EEI Agreement shall govern this Transaction; provided, however, that for purposes of calculating a Party's Collateral Requirement pursuant to Paragraph 3 of the Transition Collateral Annex, with respect to this Transaction only (i) if Seller has Exposure to Buyer, then the amount of Exposure for this Transaction is deemed to be zero dollars ($0), and (ii) in no event shall Buyer be required to post or maintain an Independent Amount with Seller.

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ARTICLE 13 OTHER 13.1

Declaration of an Early Termination Date and Calculation of Settlement Amounts

Notwithstanding anything to the contrary, the Parties shall determine the Settlement Amount for this Transaction in accordance with Section 5.2 of the Transition Master Agreement. Furthermore, with respect to this Transaction only, the following language is to be added at the end of Section 5.2 of the Transition Master Agreement: “If Buyer is the Non-Defaulting Party and Buyer reasonably expects to incur penalties, fines or costs from the CPUC, the CAISO, or any Governmental Body having jurisdiction, because Buyer is not able to include the applicable Contract Quantity in any applicable RAR Showing or, Local RAR Showing or Flexible RAR Showing due to Seller’s Event of Default, then Buyer may, in good faith, estimate the amount of those penalties or fines and include this estimate in its determination of the Settlement Amount, subject to accounting to Seller when those penalties or fines are finally ascertained. If this accounting establishes that Buyer’s estimate exceeds the actual amount of penalties or fines, Buyer shall promptly remit to Seller the excess amount. The rights and obligations with respect to determining and paying any Settlement Amount or Termination Payment, and any dispute resolution provisions with respect thereto, shall survive the termination of this Transaction and shall continue until after those penalties or fines are finally ascertained.” ACKNOWLEDGED AND AGREED TO AS OF [__________________],OCTOBER 15, 2012: [Seller]

Sycamore Cogeneration Company

Southern California Edison Company

By:

By:

Name: Neil Burgess

Name: Marc L. Ulrich

By:

By:

Name:

Name:

Title:

Title:

Date:

Date:

Title: Executive Director

Title: Vice President, Renewable and Alternative Power

Date:

Date:

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2012 CHP RA Capacity

APPENDIX A GENERATING UNIT INFORMATION (a)

Generating Unit # 2 Name: ___________________Sycamore Cogeneration Company Generating Unit # 2

Location: _________________ CAISO Resource ID: ______________ Unit NQC (as of the Confirmation Effective Date): __________ MW Unit Quantity: ___________ MW Bakersfield, California Resource Type: _________________ Other- Frame7E Resource Category (1, 2, 3 or 4): _________ 4 Point of interconnection with the CAISO Controlled Grid ("Substation"): ________ “Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the Vestal-Magunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): _____ South Local Capacity Area (if any, as of Confirmation Effective Date): ________ Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: ____________________________________________________________ Run Hour Restrictions: ____________________ Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour (b)

Generating Unit # 4 Name: Sycamore Cogeneration Company Generating Unit # 4

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Location: Bakersfield, California Resource Type: Other- Frame7E Resource Category (1, 2, 3 or 4): 4 Point of interconnection with the CAISO Controlled Grid (“Substation”): Between circuit breakers 412 and 512 in the Kern River Cogeneration Company 230 kV switchyard to the VestalMagunden 230 kV line, as identified in Appendix 1.6 to the Transition Tolling Confirmation Path 26 (North, South or None): South Local Capacity Area (if any, as of Confirmation Effective Date): Big Creek - Ventura Deliverability restrictions, if any, as described in most recent CAISO deliverability assessment: None Run Hour Restrictions: All restrictions per unit: (1) maximum 700 hours run time per calendar year, (2) no more than two (2) starts per day for a maximum of one hundred thirty (130) starts per calendar year, (3) minimum run time one (1) hour, and (4) minimum down time between starts: one (1) hour

22

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Appendix C

Report of the Independent Evaluator Two Sets of Transition Power Purchase Agreements

Southern California Edison Company and Sycamore Cogeneration Company

Southern California Edison Company and Kern River Cogeneration Company

Merrimack Energy Group, Inc. and New Energy Opportunities, Inc.

December 2012

Table of Contents I.

INTRODUCTION AND EXECUTIVE SUMMARY

1

II. BACKGROUND

5

A.

5

The Settlement Agreement and the Standard Transition PPA

B. The Existing Sycamore and KRCC PPAs, the Sycamore RFO Agreements, and the Transition PPA Negotiations

III. A.

THE ROLE OF THE INDEPENDENT EVALUATOR The Requirement for an Independent Evaluator

9

15 15

B. The Role Played by the Independent Evaluator With Respect to the KRCC and Sycamore Transition PPAs 17

IV. REASONABLENESS OF PRICING, FAIRNESS AND REASONABLENESS OF SCE’S CONDUCT OF THE NEGOTIATIONS AND WHETHER SCE TREATED KRCC AND SYCAMORE, ITS AFFILIATES, IN A NON-PREFERENTIAL MANNER 21 A.

Introduction

21

B. KRCC and Sycamore’s Eligibility for, and Compliance With, the Standard Transition PPA for Baseload Capacity and Its Right to Contracts for Dispatchable Capacity for the Transition Period

22

D. The Reasonableness of the Pricing Provisions, Especially the Capacity Prices for the Dispatchable Capacity

28

E. The Reasonableness of the Non-Pricing Related Terms and Conditions of the Transition PPAs and the Transition Dispatchable Agreements 34 F.

SCE’s Internal Mechanisms to Review the KRCC/Sycamore Transition Agreements

40

G.

Consistency With FERC Principles

40

V.

CONCLUSION: DOES THE CONTRACT MERIT COMMISSION APPROVAL? 43

Public Appendix—Extension Letters Confidential Appendix

I.

Introduction and Executive Summary

On October 15, 2012, Southern California Edison Company (“SCE”) executed, pursuant to the “Qualifying Facility and Combined Heat and Power Program Settlement Agreement” (“CHP Settlement” or “Settlement”), a power purchase agreement (“PPA”) for baseload generation with Sycamore Cogeneration Company (“Sycamore”) with respect to two of the four generating units of the approximately 300 MW Sycamore Cogeneration Facility (“Sycamore Project”). This PPA (the “Sycamore Transition PPA”) is based on the Transition Standard Contract for Existing Qualifying Cogeneration Facilities (“Standard Transition PPA”), which is part of the CHP Settlement. As part of the same transaction, SCE also signed several other agreements pursuant to which Sycamore will provide dispatchable capacity, energy and other products from the two other Sycamore generating units. The latter agreements (collectively, the “Sycamore Transition Dispatchable Agreements”) consist of the Resource Adequacy Confirmation (“Sycamore Transition RA Confirmation”), pursuant to which Sycamore will provide Resource Adequacy (“RA”) capacity to SCE, a Unit Contingent Toll Confirmation (“Sycamore UC Transition Toll Confirmation” or “Sycamore Transition UC Toll”) pursuant to which Sycamore will provide dispatchable capacity (other than RA), energy and other products, which are both subject to an EEI Master Power Purchase and Sale Agreement, also effective October 15, 2012 and Paragraph 10 to the Collateral Annex executed as of the same date, including applicable annexes and appendices (“Sycamore Transition EEI Master Agreement”). Sycamore is owned 50% by an indirect wholly-owned subsidiary of Edison Mission Group, Inc. (“Edison Mission”), an affiliate of SCE, and 50% by an indirect wholly-owned subsidiary of Chevron Corporation (“Chevron”). On October 15, 2012, SCE and Kern River Cogeneration Company (“KRCC”) executed substantially identical agreements to the Sycamore Agreements. KRCC is owned 50% by an indirect wholly-owned subsidiary of Edison Mission, an affiliate of SCE, and 50% by an indirect wholly-owned subsidiary of Chevron. KRCC is thus also an affiliate of SCE, is a sister company to Sycamore, is under common management, and owns a project, the “KRCC Project,” that is substantially similar to the Sycamore Project. The Sycamore and KRCC agreements were negotiated together. Performance under these agreements would commence upon receipt of regulatory approvals by the California Public Utilities Commission (“CPUC” or “Commission”) and the Federal Energy Regulatory Commission (“FERC”) and would end no later than June 30, 2015. The agreements (“Transition Agreements”) for which regulatory approval is sought are: 1. Sycamore (collectively, the “Sycamore Transition Agreements”): a. Sycamore Transition PPA b. Sycamore Transition Dispatchable Agreements:

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1. 2. 3.

Transition EEI Master Agreement Transition RA Confirmation Transition Toll Confirmation 1

2. KRCC (collectively, the “KRCC Transition Agreements”) : a. KRCC Transition PPA KRCC Transition Dispatchable Agreements: b. 1. Transition EEI Master Agreement Transition RA Confirmation 2. 3. Transition Toll Confirmation

The CHP Settlement requires SCE and California’s other major investor-owned utilities to conduct competitive solicitations to acquire power products from eligible facilities. In July 2012, SCE and Sycamore signed contracts similar to the Sycamore Transition Agreements for a seven-year term starting January 1, 2014 (the “Sycamore RFO Agreements”) pursuant to SCE’s first Combined Heat and Power Request for Offers (“CHP RFO”). Regulatory approval for these transactions is pending before the CPUC and FERC.2 With respect to the Sycamore Transition Agreements, the term will end on the day immediately prior to the start dates of the Sycamore RFO Agreements, but if regulatory approvals are not obtained prior to June 30, 2014, the end of the term is June 30, 2015. With respect to the KRCC Transition Agreements, the term ends June 30, 2015; however, KRCC has the right under the Standard Transition PPA and the CHP Settlement to terminate the transition agreements prior to the end of the term if KRCC has been selected by a California investor-own utility that is a party to the Settlement in a competitive solicitation or if KRCC enters into a power sale agreement pursuant to such a solicitation. The CHP Settlement had been negotiated by SCE, the two other major investor-owned utilities (“IOUs”) in California, four advocacy groups for combined heat and power (“CHP”)/qualifying facilities (“QFs”) and other independent generators, and two ratepayer advocacy organizations.3 Necessary regulatory approvals were received from the CPUC in Decision 10-12-035 and 1

The KRCC transition agreements executed on October 15, 2012 are: (a) a baseload Power Purchase and Sale Agreement (“KRCC Transition PPA”), based on the Standard Transition PPA, pursuant to which KRCC will supply capacity and energy from two generating units operating in baseload mode (firm and as-available capacity) and (b) other agreements pursuant to which Sycamore will provide dispatchable capacity, energy and other products from two other Sycamore generating units. The latter agreements (collectively, the “KRCC Transition Dispatchable Agreements”) consist of the Resource Adequacy Confirmation (“KRCC Transition RA Confirmation”), pursuant to which KRCC will provide RA capacity to SCE, and a Unit Contingent Toll Confirmation (“KRCC UC Transition Toll Confirmation” or “KRCC Transition UC Toll”) pursuant to which KRCC will provide dispatchable capacity (other than RA), energy and other products, which are both subject to an EEI Master Power Purchase and Sale Agreement, also effective October 15, 2012 and Paragraph 10 to the Collateral Annex executed as of the same date, including applicable annexes and appendices (“KRCC Transition EEI Master Agreement”). 2 SCE filed an advice letter with the CPUC for approval of the Sycamore RFO Agreements on October 1, 2012 (Advice 2784-E). Sycamore and SCE filed for FERC approval on October 16, 2012 (Docket ER13-133). 3 The parties to the CHP Settlement were SCE, Pacific Gas and Electric Company, San Diego Gas & Electric Company, Independent Energy Producers Association, Cogeneration Association of California, California Cogeneration Association, Energy Producers and Users, Coalition, The Utility Reform Network, and the Division of Ratepayer Advocates.

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subsequent orders4 and the FERC,5 with FERC granting an application to terminate the California IOU’s mandatory purchase obligation pursuant to section 201(m) of the Public Utility Regulatory Policies Act of 1978 (“PURPA”).6 The Settlement became effective on November 23, 2011 (“Settlement Effective Date”).7 Both the Sycamore and KRCC projects are located near Bakersfield, California. Each project consists of four natural-gas fired combustion turbines and heat recovery steam generators and provides steam to Chevron U.S.A., Inc. (“CUSA”), an indirect wholly-owned subsidiary of Chevron, for enhanced oil recovery purposes. Sycamore is owned 50% by Chevron Sycamore Cogeneration Company, a wholly-owned subsidiary of CUSA, and Western Sierra Energy Company, an indirect wholly-owned subsidiary of Edison Mission. KRCC is owned 50% by Chevron Kern River Cogeneration Company, a wholly-owned subsidiary of CUSA, and Southern Sierra Energy Company, an indirect wholly-owned subsidiary of Edison Mission. Both SCE and Edison Mission are wholly-owned subsidiaries of Edison International. Under the “hybrid” Transition Agreements, Sycamore and KRCC will provide a mix of baseload capacity and energy and dispatchable capacity and energy to SCE. In connection with the negotiations between SCE and KRCC/Sycamore for a Transition Power Purchase Agreement (“Transition PPA”) pursuant to the CHP Settlement, SCE retained Merrimack Energy Group, Inc. (“Merrimack Energy”) to serve as Independent Evaluator (“IE”) to monitor the contract negotiations consistent with SCE’s policies regarding transactions with affiliates, CPUC rules, and FERC guidelines and to provide a report on its monitoring efforts to the appropriate regulatory commissions. Previously, Merrimack Energy had been retained as IE to oversee SCE’s first competitive solicitation for long-term purchase contracts from eligible facilities under the CHP Settlement as well as to monitor other contract negotiations for a Transition PPA between SCE and another affiliate, Watson Cogeneration Company (“Watson”).8 This report is submitted to communicate the results of the IE’s oversight of the negotiations and resulting Transition PPAs between SCE and KRCC/Sycamore to the CPUC and FERC. Contemporaneous with this IE report, SCE is filing an advice letter for approval of the Sycamore Transition Agreements and the KRCC Transition Agreements, in compliance with CPUC rules

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Decision Adopting Proposed Settlement, D.10-12-035 (December 21, 2010), Decision Granting Petition to Modify Decision 10-12-035, D. 11-07-010 (July 15, 2011), Decision Granting, In Part, Petition to Modify Decision 11-07010 and Request to Establish a Settlement Agreement Effective Date and Grant Motion for Closure, D. 11-10-016 (October 11, 2011), Order Dismissing Application for Rehearing of Decision 10-12-035 (October 18, 2011), and Order Denying Rehearing of Decision 10-12-035 On Certain Issues Raised by the City and County of San Francisco (October 24, 2011). 5 Order Granting Application to Terminate Purchase Obligation, 135 FERC ¶ 61,234 (June 16, 2011). 6 16 U.S.C. § 824a-3(m) (2006). 7 The CPUC’s orders of approval became final and non-appealable 30 days after the issuance on October 24, 2011 of the CPUC’s Order Denying Rehearing of Decision 10-12-035 On Certain Issues Raised by the City and County of San Francisco. 8 In connection with SCE’s procurement activities pursuant to the CHP Settlement, the IE has previously authored reports with respect to each of the contracts executed by SCE as a result of the CHP RFO, including the Sycamore RFO Agreements, and a Transition PPA executed by SCE with Watson, SCE’s affiliate. See SCE Advice Letters 2763-E, 2770-E, 2771-E, 2772-E, and 2784-E.

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requiring CPUC approval of power contracts between affiliates.9 Approval is also required by FERC under Section 205 of the Federal Power Act to demonstrate that the contract for the sale for resale of electric power between an affiliate seller and a utility purchaser with captive retail customers was not the product of undue preference in favor of the affiliated seller. An application for such approval is also being filed with FERC. The key issues addressed in this report are whether the pricing and other terms and conditions of the Sycamore and KRCC Transition Agreements represented a reasonable implementation of the Settlement Agreement and were not unduly preferential to SCE’s affiliates. The Standard Transition PPA applicable to baseload operating CHP facilities contain standard pricing, as well as standard terms and conditions, for which Sycamore and KRCC were entitled but there is no standard pricing or standard terms and conditions applicable to the dispatchable generating units under the Settlement Agreement. The parties disagreed sharply on the standard under the CHP Settlement applicable to dispatchable capacity under agreements covering the Transition Period under the Settlement Agreement—KRCC/Sycamore asserting that the “competitive market price” referenced in the Settlement Agreement was for CHP facilities with dispatchable generation only and SCE asserting that it applied to generation in the California market more broadly. The parties ultimately agreed to a combined capacity price between the RA Confirmation and the UC Toll Confirmation of $51.96/kW-year. With regard to pricing for the dispatchable capacity, the IE’s opinion is that the reasonableness of the pricing is dependent on one’s interpretation of the Settlement Agreement and the applicability of evidence provided by SCE in support of the contractual capacity pricing. With regard to whether SCE has implemented this portion of the Settlement Agreement on a nonpreferential basis, one cannot make a comparison to treatment of non-affiliates because, to the IE’s knowledge, the only CHP facilities under contract to SCE with dispatchable capacity are those of its three affiliates, KRCC, Sycamore, and Watson, and the negotiations with Watson are still ongoing.10 In its oversight role, the IE was required to focus on the Settlement Agreement itself, the conduct of the negotiations, and the evidence of extrinsic pricing in assessing whether SCE treated its affiliates on a preferential basis. SCE, on the one hand, and KRCC and Sycamore, on the other hand, negotiated contractual terms and conditions and modifications to the pro forma Dispatchable Agreements for the dispatchable units primarily in relation to the Sycamore RFO Agreements, which had been negotiated in the context of SCE’s first CHP RFO. Since this IE monitored the negotiation of the Sycamore RFO Agreements and found them to be negotiated on a non-preferential basis,11 the IE’s monitoring of the Sycamore and KRCC Transition Agreements focused on modifications to terms and conditions from the Sycamore RFO Agreements as well as on modifications to the Standard 99

Decision 06-12-029 (December 20, 2006) adopting revised affiliate transaction rules, Appendix A-3, Rule III.B.1.

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While any owner of an eligible CHP facility under the Settlement Agreement may submit an offer in any California IOU’s CHP RFO, Transition Agreements applicable to the Transition Period may only be between a CHP facility and the IOU which it had a Legacy PPA (or extension of a Legacy PPA). 11 Advice 2784-E, Appendix B.1, IE Report, p. 43.

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Transition PPA. The IE found those modifications to be reasonable and not the result of preferential treatment to an affiliate. With regard to the negotiated price for dispatchable capacity under the Transition Dispatchable Agreements, the IE’s conclusions can be summarized as follows: 1. If “competitive market price” is interpreted as meaning the general CAISO market place and is not limited to CHP dispatchable facilities only: a. The $51.96/kW-year contract price has not been supported by benchmark evidence regarding market prices for similar transactions; b. The $51.96/kW-year contract price can be justified if CAISO’s $67.50 Capacity Pricing Mechanism pricing for backstop capacity or SCE’s 2012 RA contract with the Sutter project are the relevant “benchmarks” on the basis that there is a serious likelihood that the KRCC and Sycamore projects may shut down unless nonmarket pricing is available and there is a reliability need for the generating units; however, factual support regarding the likelihood of shut down or the reliability need for the generating units has not been provided; 2. If “competitive market price” is limited to CHP dispatchable facilities only, the $51.96/kWyear contract price is supported by extrapolating from benchmark evidence; 3. If the Settlement Agreement is so ambiguous so that neither interpretation can be embraced, the $51.96/kW-year contract price could be supported in light of the savings to ratepayers flowing from the Transition Agreements relative to continuation of the higher-priced Legacy PPAs (based on the possibility that the Legacy PPAs would continue to have been extended by the CPUC’s Energy Division).   In this report, we first review the pertinent provisions of the CHP Settlement and the history of negotiations between the parties.

II.

Background

A. The Settlement Agreement and the Standard Transition PPA The CHP Settlement was negotiated over an extended period by the California IOUs, representatives of California’s QFs/CHPs, and ratepayer advocates to replace California’s CHP PURPA Program, and was approved by the CPUC, after input from other interested parties. The Settlement includes a multi-year transitional period where Existing CHP Facilities whose contracts were expiring could sell capacity and energy under standard contracts at standard capacity rates and at energy rates under standardized rate formulas.

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The CHP Settlement is embodied in the CHP Program Settlement Agreement Term Sheet dated October 8, 2010 (“Settlement Agreement”). The Settlement Agreement requires that the three major California IOUs enter into new PPAs with eligible facilities under the Settlement in specified amounts (subject to various qualifications) with an objective of achieving certain levels of greenhouse gas (“GHG”) emission reductions. Specifically, in the “Initial Program Period,” starting with the Settlement Agreement effective date, November 23, 2011, and concluding 48 months afterwards, each IOU is required to conduct three Requests for Offers (“RFOs”) with the goals of entering into new PPAs with either new CHP facilities or existing CHP facilities that have changed operations to convert to utility-scheduled dispatchable facilities (sometimes referred to as “Utility Prescheduled Facilities” or “UPFs”12). SCE’s MW target for the Initial Program Period is 1,402 MW. This new statewide CHP program has a number of goals and objectives which are set forth in the Settlement Agreement. Among them are the retention of existing efficient CHP, support for changes in operations and upgrades of inefficient CHP to provide greater benefits, providing an orderly exit for CHP facilities that cannot participate, or are unsuccessful, in the new CHP program, retaining existing CHP GHG emissions reductions benefits and incrementally reducing GHG emissions through new or repowered CHP or changes in operations in existing CHP facilities, and the resolution of long-standing disputes and litigation regarding California’s prior QF CHP PURPA Program.13 Overlapping with the Initial Program Period is the “Transition Period,” commencing with the Settlement Agreement effective date and extending until July 1, 2015, where a CHP facility “will either obtain a new PPA . . ., sell into the wholesale market, shut down, or cease to export to the grid.14 During the Transition Period, a “CHP Facility currently selling to an IOU under a Legacy PPA or an extension thereof that is expiring during the Transition Period, may sign a Transition PPA with the same IOU-Buyer.”15 The Transition PPA begins upon the expiration of the Legacy PPA or extension thereof and ends at the election of the Seller, but no later than July 1, 2015. A “Legacy PPA” is defined under the Settlement Agreement as an existing QF PPA, including an extension of a QF PPA, that is in force and effect on the Settlement Effective Date, but excludes PPAs entered into pursuant to California’s Renewable Portfolio Standard (“RPS”) Program. The Standard Transition PPA is a standard form agreement applicable to CHP facilities operating in baseload mode with pricing formulas established under the Settlement Agreement. The Standard Transition PPA was the product of negotiations by the CHP Parties. In terms of capacity prices, there is a firm capacity price of $91.97/kW-year for all years through 2015 (Section 1.06(a)) and an as-available capacity price that is $43.09/kW-year in 2012 with 12

Under the CHP Settlement, a “UPF” or “Utility Prescheduled Facility” is “[a]n Existing CHP Facility that has changed operations to convert to a utility controlled scheduled dispatchable generation facility, including but not limited to an EWG.” 13 See Settlement Agreement Section 1. 14 Settlement Agreement § 2.1.1. 15 Settlement Agreement § 3.1.1. QFs of 20 MW or less in capacity are also entitled to a standard contract under PURPA. Settlement Agreement § 4.5.

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higher amounts in subsequent years.16 The firm capacity prices are the same prices that the CPUC determined should be paid to QFs in D. 07-09-040 issued on September 25, 2007 (the “2007 Decision”). The as-available capacity prices are apparently consistent with the methodology in the 2007 Decision adopted for determining as-available capacity prices. Under the Settlement Agreement, the QF has the right to designate the amount of firm contract capacity and as-available capacity offered for each month of the year. Annual energy deliveries cannot exceed the lower of (a) the net contract capacity (the sum of firm capacity and asavailable capacity) at 100% capacity factor applied over the term year and (b) historical energy deliveries. Capacity payments are allocated based on time-of-delivery (“TOD”) periods—there are six such periods for SCE—with the highest payments ordinarily occurring during the summer on-peak period due to a high capacity payment allocation factor. For firm capacity, there is an availability adjustment provision (applied during each TOD period) with reductions in capacity payments applied if availability is less than 95% with no payments if availability is less than 60% (subject to allowances for transmission curtailments, maintenance outages and force majeure events).17 Energy payments are formulaic. They are based on the amount of energy delivered (subject to a cap) multiplied by the Energy Price. The Energy Price is determined by multiplying a contractually specified heat rate by a formula-based natural gas price, plus a Variable O&M charge, the sum of which is multiplied by a TOD factor.18 In addition, there is a locational adjustment and an adder for GHG compliance cost charges.19

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As-available capacity rates are $45.00 in 2013, $46.97 in 2014, and $48.98 in 2015. Standard Transition PPA, Exhibit D Section 3(b). 17 There are no bonus payments if availability during a TOD period exceeds 95%. As-available capacity payments are made only when the facility produces energy above the firm contract capacity on an hourly basis up to the net contract capacity and are not subject to any availability adjustment. 18

The burner tip gas price is determined in accordance with the 2007 Decision and Resolution E-4246. The Variable O&M Charge is specified by the 2007 Decision and Resolution E-4246. The contractually-specified heat rate differs by year of energy deliveries. For 2012, it is 8,225 Btu/kWh; for 2013 and 2104, it is 8,125 Btu/kWh; for 2015, it is a Market Heat Rate determined in accordance with the 2007 Decision and Resolution E-4246. For SCE, the Burner Tip Gas Price is determined by the natural gas market price at Topock (California border) plus intrastate transportation costs using gas transportation tariff components identified in Resolution E-4246. The Variable O&M Charge is $2.50/MWh ($.0025/kWh) in 2004 escalated on a monthly basis by 2% per year ($2.93/MWh in 2012). The Market Heat Rate, applicable to energy deliveries from January 1, 2015 through June 30, 2015, is determined by a formula that subtracts the forward variable O&M factor from forward market energy prices and divides the difference by forward delivered natural gas costs. 19

Their locational adjustment is based on the hourly difference between (a) the Day Ahead Locational Marginal Price at the interface between the Generating Facility and the CAISO grid and (b) the trading hub for the applicable zone. There is also an adder for GHG compliance cost charges. California’s GHG emissions cap-and-trade program (pursuant to AB 32) is scheduled to commence in January 2013. Once the program commences and during the first compliance period, SCE is responsible for compensating the Sellers for GHG emissions compliance costs based on the higher of the price formula without specific GHG compliance costs and a price formula providing for recovery of GHG allowance costs.

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The form of the Standard Transition PPA is the California IOU QF Standard Offer Contract modified for the Transition Period and contains a variety of modifications described in the Settlement Agreement.20 The Settlement Agreement has a specific section that, on its face, appears to be applicable to Existing CHP facilities that seek to provide dispatchable capacity to a California IOU during the Transition Period—Section 3.4.1.2, which is entitled “Sale of Additional Dispatchable Capacity beyond the Transition PPA Capacity Product.” This option for Additional Dispatchable Capacity is viewed as being limited to a few CHP facilities, each with unique operational constraints. A specific amendment to the Transition PPA is required to accommodate Additional Dispatchable Capacity. The Transition PPA shall provide that a Seller may elect to deliver a standard capacity product (including associated energy and RA with such capacity) at the Transition PPA firm capacity and energy prices or as-available capacity and energy prices. In addition to these standard products, a Seller may elect to sell to Buyer under a Transition PPA Additional Dispatchable Capacity above the standard contract capacity set forth in the Transition PPA (Additional Dispatchable Capacity). Buyer must negotiate in good faith for 120 days to amend the Transition PPA to incorporate a competitive market price for the Additional Dispatchable Capacity. [emphasis added] The remainder of Section 3.4.1.2 sets forth the criteria for acceptable Additional Dispatchable Capacity under a Transition PPA and procedures to address the inability of a Seller and the Buyer-IOU to agree on a “competitive market price” and other terms regarding Additional Dispatchable Capacity. If negotiations are unsuccessful, Buyer and Seller will mediate the terms of the amendment using the mediation procedures set forth in Section 10.02 of the Transition PPA. Within ninety (90) days after the Transition PPA is executed by Buyer and Seller, Seller shall designate the initial Additional Dispatchable Capacity offered to Buyer for the term of the PPA. In addition, such Additional Dispatchable Capacity will be offered with an associated fixed heat rate, or fixed heat rate curve, established by the Seller. .... If the Buyer elects not to accept Seller’s offer of Additional Dispatchable Capacity for the term of the Transition PPA, then the Buyer, as the Scheduling Coordinator, will facilitate an alternative sale and delivery of the Dispatchable Capacity to the CAISO market, as long as such capacity meets the CAISO determined requirements for compliance with the CAISO Tariff and Protocols. As indicated before, on November 23, 2011, the CHP Settlement Agreement became effective. Under Section 3.1.1 of the Settlement Agreement, a CHP facility currently selling to an IOU 20

Settlement Agreement § 3.3.1 and 3.4.

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under a Legacy PPA or an extension of a Legacy PPA that is expiring during the Transition Period may sign a Transition PPA with the same IOU-Buyer.

B. The Existing Sycamore and KRCC PPAs, the Sycamore RFO Agreements, and the Transition PPA Negotiations The KRCC project which, like the Sycamore project, is located near Bakersfield, California, has similar origins and ownership, but converted several years ago to a “hybrid” baseload and dispatchable project. The original KRCC contract was entered into on January 16, 1984, with a term of 20 years following initial operation. In 2005, SCE and KRCC entered into an Amended and Restated Parallel Generation Agreement (“2005 Agreement”). The 2005 Agreement was approved by the CPUC in D. 06-05-034 in May 2006. Under the 2005 Agreement, KRCC operates two generating units as baseload units and the other two generating units as dispatchable units for a five-year term. KRCC is currently selling baseload and dispatchable capacity and energy to SCE under an extension of its prior PPA (an extension of a Legacy PPA under the Settlement Agreement). On June 29, 2011, SCE and KRCC entered into a letter agreement extending the term of the 2005 Agreement pursuant to the 2007 Decision. Pricing for the baseload units, as well as the capacity pricing for the dispatchable units, however, is determined under the 2007 Decision--$91.97/kW-year. While the firm capacity price under the Standard Transition PPA is the same as under the 2007 Decision, the performance standards under the Legacy PPAs are less stringent than under the Standard Transition PPA for the baseload capacity. In addition, the capacity price for KRCC’s dispatchable units under the Legacy PPA is significant higher than the current market price for capacity and the $51.96/kW-year in the KRCC and Sycamore Transition Dispatchable Agreements. Sycamore’s predecessor in interest, KRCC, signed a PPA with SCE in December 1984 for the planned Sycamore Project based on a QF standard offer contract, with a term of 20 years following commercial operation. In 1986, KRCC assigned the PPA to Sycamore, with SCE’s consent, and Sycamore and SCE amended and restated the PPA. Under the amended and restated PPA, Sycamore would sell a minimum of 284 MW of contract capacity and baseload energy. A four-unit combustion turbine cogeneration facility was placed into commercial operation in 1988. In June 2008, SCE and Sycamore entered into a letter agreement, under which SCE would pay, pursuant to the 2007 Decision, a capacity price of $91.97/kW-year for the firm capacity of 300 MW, without provision for any bonus payments, and make energy payments to Sycamore in accordance with the Market Index Formula set forth in the 2007 Decision and subsequent rulings. KRCC’s and Sycamore’s Transition Period proposals were predicated on there being a reduced need for thermal energy for enhanced oil recovery purposes at the nearby Kern River oil field. Declining need for thermal energy means that KRCC and Sycamore are less able to sustain baseload operations in an economic manner over time. Converting to dispatchable operations, in the case of Sycamore, and maintaining dispatchable operations, in the case of KRCC, provides SCE with flexibility not to purchase energy from the dispatchable units when it is more 9

expensive for KRCC and Sycamore to produce energy than it is for SCE to purchase energy from the market. Section 11.2.1 of the Settlement Agreement provides that absent an extension approved by the Director of the CPUC’s Energy Division or during the pendency of any request for an extension, Legacy PPAs under extension due to prior CPUC orders would remain in effect for up to 120 days after the Settlement Effective Date—March 22, 2012, 120 days after November 23, 2011— at which time the IOU-Buyer and the Seller would have entered into a Transition PPA or other Subsequent PPA.21 Buyers and Sellers are required to use all reasonable efforts to enter into a Transition PPA, if applicable, within 120 days after the Settlement Effective Date. The Director of the Energy Division is authorized to act on requests for extensions, which may be granted for good cause. However, requests for extensions “shall not be unreasonably repetitive or designed primarily to delay termination of the extension of the Legacy CHP PPA.” KRCC/Sycamore initiated inquiries about a transition contract at a meeting held by SCE for QF’s regarding the Settlement Agreement on July 22, 2011. Initial discussions between KRCC/Sycamore and SCE regarding a transition agreement commenced with a conference call on August 9, 2011. The IE attended the conference call, as well as all subsequent conference calls and meetings regarding negotiations pertaining to the Transition PPA. Initial discussions focused on the form of agreement(s), and KRCC/Sycamore agreed to draft a proposed agreement and send it to SCE (pricing provisions for the dispatchable units were not included). KRCC/Sycamore sent an initial draft of the proposed contract in late December, but it did not include pricing provisions. SCE requested a pricing proposal from KRCC/Sycamore and a term sheet. KRCC/Sycamore followed up with a proposed term sheet, including pricing and other key commercial terms, in late January 2012. In March 2012, SCE responded that KRCC/Sycamore’s proposed pricing was above-market, in SCE’s opinion and, therefore, unacceptable. SCE gave KRCC/Sycamore the opportunity to “refresh” the offer, which KRCC/Sycamore declined. KRCC/Sycamore requested that SCE make a counter-offer, but SCE declined to make a counter-offer at the time. It soon became evident that the parties had very different interpretations of the Settlement Agreement and how it applied to the matter at hand. KRCC/Sycamore expressed the desire to enter into an agreement (or agreements) for the Transition Period that would cover both the generating units that would operate in a baseload manner as well as the generating facilities that would operate as dispatchable facilities. SCE was willing to negotiate such an agreement, but only if it could not be done in a mutually acceptable manner within the timeframes provided under the Settlement Agreement. SCE’s position was that KRCC and Sycamore should enter into standard Transition PPAs for the baseload capacity and then the parties should negotiate a “competitive market price” for the dispatchable capacity and, upon reaching agreement, modify the Transition PPAs to incorporate terms and conditions for the dispatchable capacity. 21

“Subsequent PPA” is defined in Section 11.2.1 as a “new or amended PPA.” A Transition PPA is a form of Subsequent PPA.

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SCE relied on Section 3.4.1.2 of the Settlement Agreement: “Sale of Additional Dispatchable Capacity beyond the Transition PPA Capacity Product.” The Transition PPA shall provide that a Seller may elect to deliver a standard capacity product (including associated energy and RA with such capacity) at the Transition PPA firm capacity and energy prices or as-available capacity and energy prices. In addition to these standard products, a Seller may elect to sell to Buyer under a Transition PPA Additional Dispatchable Capacity above the standard contract capacity set forth in the Transition PPA (Additional Dispatchable Capacity). Buyer must negotiate in good faith for 120 days to amend the Transition PPA to incorporate a competitive market price for the Additional Dispatchable Capacity. If negotiations are unsuccessful, Buyer and Seller will mediate the terms of the amendment using the mediation procedures set forth in Section 10.02 of the Transition PPA. Within ninety (90) days after the Transition PPA is executed by Buyer and Seller, Seller shall designate the initial Additional Dispatchable Capacity offered to Buyer for the term of the PPA. . . . If the Buyer elects not to accept Seller’s offer of Additional Dispatchable Capacity for the term of the Transition PPA, then the Buyer, as the Scheduling Coordinator, will facilitate an alternative sale and delivery of the Dispatchable Capacity to the CAISO market, as long as such capacity meets the CAISO determined requirements for compliance with the CAISO Tariff and Protocols. With the March 22, 2012 deadline for entering into a Transition PPA nearing, KRCC/Sycamore supported and joined a request by another SCE affiliate, Watson, for a blanket extension of time to enter into a Transition PPA or other Subsequent PPA from the CPUC’s Director of the Energy Division.22 In a response, SCE supported an extension, but to no later than June 1, 2012, which would apply to all QF’s on extended PPAs (including, but not limited to, Watson, KRCC and Sycamore.23 On March 20, 2012, the Director of the Energy Division granted the extension to the dates proposed by SCE.24 In the spring of 2012 (and in the first six months of 2012 in general), KRCC, Sycamore and SCE were spending considerable time in the conduct of the first CHP RFO pursuant to the Settlement Agreement. SCE issued its RFO in December 2011, received offers in February 2012, announced its short list in March 2012, negotiated contracts with short listed offerors through May 2012, when final offers were submitted, made final selections in June 2012, and executed final offers by early July 2012. Meanwhile, KRCC and Sycamore were actively involved in the process as offerors in both SCE’s and Pacific Gas and Electric Company’s RFOs.25 During this 22

KRCC and Sycamore submitted their joint request for an extension on March 8, 2012. Watson had previously submitted a request on February 22, 2012. 23 One of SCE’s goals for a limited extension was to ensure that there would be adequate time for the completion of interconnection agreements. 24 The Energy Division’s letters responding to requests for extensions, as well as the requests and responses to the requests, are included in the Public Appendix to this report. 25 Letter dated May 18, 2012 from Neil Burgess, Executive Director of KRCC and Sycamore, to Edward Randolph, Director, Energy Division.

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period, Sycamore negotiated contract terms with SCE for a seven-year contract starting in 2014 in the March-May period and was awarded a contract with SCE, which was executed on July 2, 2012. Negotiations regarding transition agreements were not especially productive during this period. On May 18, 2012, KRCC and Sycamore sought an additional extension of 180 days from the Energy Division.26 SCE opposed the request. On May 31, 2012, the Energy Division’s Executive Director agreed with SCE’s position that the terms of Additional Dispatchable Capacity may be negotiated as an amendment to, or modification of, the Transition PPA. Contrary to KRCC/Sycamore’s arguments, Director Randolph stated that Section 3.4.1.2 of the Settlement Agreement was pertinent to the situations presented by KRCC, Sycamore and Watson—that “the Settlement provides an opportunity to modify the pro forma Transition PPA to include provisions that would allow facilities like Watson, KRCC and Sycamore to sell multiple power products.” He denied Watson’s, KRCC’s and Sycamore’s requests for further extensions. Following further requests for extensions by KRCC/Sycamore and Watson, the Energy Division, on June 1, 2012, extended the date for execution of a Transition PPA or other Subsequent PPA to June 8, 2012. On June 8, 2012, following a meeting between the Energy Division and KRCC/Sycamore on June 6, 2012,27 the Energy Division granted an extension to KRCC and Sycamore until October 1, 2012 to negotiate an amended Transition PPA or other Subsequent PPA with SCE. In the Executive Director’s letter, reference was made to SCE’s CHP RFO process, which had been in process for several months as a possible constraint on negotiations between the parties, and that it was reasonable to provide additional time to allow the parties to negotiate, since the CHP RFO process was expected to be concluded in a matter of weeks. If SCE were to exchange price information during the pendency of a solicitation before final offers were due, especially to an affiliate, it could raise issues regarding improperly advantaging a party, especially an affiliate. In this context, Director Randolph stated that “As of May 31, and certainly after July 2, 2012, SCE should have knowledge, based on its RFO, about competitive market prices for CHP facilities operating as UPFs.” With the expected conclusion of the CHP RFO on July 2, 2012, the potential constraint on bilateral negotiations would be diminished or eliminated. Hence, he concluded that “It is reasonable to allow the parties to continue negotiations after this constraint on bilateral negotiations goes away.” Those negotiations were to address pricing and other terms and conditions for dispatchable (UPF) capacity. KRCC and Sycamore had expressed concern that entering into a pro forma Transition PPA for baseload generation only might force them to shut down (“Under the terms of the pro forma Transition PPA, generating units seeking to operate as UPFs could be forced to cease operations unless the Transition PPA can be successfully amended to include provisions for generators operating as UPFs.”) The parties, for some time, had expressed very different views on the applicable standard under the Settlement Agreement for pricing for dispatchable capacity for an agreement during the 26 27

Watson had also sought a similar extension the previous day. The IE attended by telephone, at the request of Energy Division.

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Transition Period. SCE’s position was that the “competitive market price” language in Section 3.4.1.2 was applicable and that it referred to competitive market prices for capacity in the CAISO market generally taking into consideration (a) the relatively short term of the agreement (201315) and (b) the high heat rates of KRCC and Sycamore, which are approximately 12,300 Btu/kWh. KRCC and Sycamore’s position was that the market price of capacity was for dispatchable capacity from projects qualifying as CHP facilities under the Settlement Agreement. On August 1, 2012, SCE proposed mediation. This was, in the IE’s view, consistent with Section 3.4.1.2 of the Settlement Agreement, which states: “If negotiations [regarding pricing for Additional Dispatchable Capacity] are unsuccessful, Buyer and Seller will mediate the terms of the amendment using the mediation procedures set forth in Section 10.02 of the Transition PPA.” While the parties did not agree on the characterization of the issue or issues to be mediated, they did agree to mediation and a mediator, CPUC Administrative Law Judge Melissa Semcer. A one-day mediation session was held in San Francisco on September 12, 2012, with representatives of SCE, KRCC/Sycamore, the mediator, and the IE in attendance. While the mediation session itself did not result in a negotiated resolution, the discussions were productive. Anticipating a further request for an extension by KRCC/Sycamore, SCE sent a letter to Director Randolph on September 25, 2012. SCE stated that no further extension should be granted, and that KRCC/Sycamore should either (1) sign the standard Transition PPAs or (2) sign Subsequent PPAs for all products on or before September 30. SCE asserted that KRCC/Sycamore had neither offered a competitive price for the dispatchable capacity nor been willing to sign standard Transition PPAs. Rather, KRCC and Sycamore have continually sought extensions, which had the effect, according to SCE, of keeping their Legacy PPAs in effect which produced higher revenues for KRCC and Sycamore and higher costs to SCE’s ratepayers. On September 27, 2012, KRCC and Sycamore, through their regulatory counsel, Michael Alcantar, sought a further extension from October 1, 2012 to October 20, 2012 to continue negotiations regarding pricing for the dispatchable facilities. Mr. Alcantar recognized that the parties have been engaged in negotiations regarding pricing and that the parties had agreed in principal to use the Sycamore Dispatchable Agreements negotiated in the CHP RFO as the basis for negotiating contract terms and conditions for the KRCC and Sycamore Transition PPAs for the dispatchable units. However, he stated that the parties had not agreed on price for the dispatchable units. He requested that the Energy Division provide direction on the appropriate standard for pricing for the dispatchable facilities, suggesting that pricing should be based on the results of the most recent CHP RFO conducted by SCE, referencing a sentence in Director Randolph’s June 8, 2012 letter—“As of May 31, and certainly after July 2, 2012, SCE should have knowledge, based on its RFO, about competitive market prices for CHP facilities operating as UPFs.” On October 2, 2012, Director Randolph granted a “final extension” to October 15, 2012. In doing so, he did not provide any guidance on the applicable standard for pricing for dispatchable facilities, as requested by KRCC and Sycamore. With this letter, I grant a final extension of the existing Legacy CHP PPAs of KRCC and Sycamore until October 15, 2012. If either of the CHP facilities executes a Subsequent 13

PPA that requires regulatory approval by this Commission and/or by FERC, I hereby grant a further extension of that facility’s existing Legacy CHP PPA until the date when the Subsequent PPA has received the required regulatory approval or denial. On October 9, 2012, Mr. Alcantar, on behalf of KRCC and Sycamore, made an “emergency request” to the Executive Director for an indefinite extension of time. In the letter, Mr. Alcantar reiterated KRCC and Sycamore’s view that capacity pricing for the dispatchable generating units should be based on Sycamore’s pricing in the CHP RFO and that it was not contemplated under the CHP Settlement that “transition pricing would be subject to negotiation.”28 SCE responded by letter dated October 10, 2012, opposing the extension request. The main material difference between what SCE has offered KRCC/Sycamore and what Sycamore negotiated in the RFO is the capacity price for the dispatchable portion of the PPAs. The reason for this price differential is that SCE must justify the price for any PPA to the Federal Energy Regulatory Commission (FERC) as consistent with prices in the short-term capacity market. SCE must do this because KRCC/Sycamore are SCE Affiliates. Accordingly, SCE must submit any PPAs with its Affiliates to FERC together with an explanation of why they are consistent with competitive market prices. It is SCE’s opinion that capacity prices for the long-term (seven-year) Sycamore CHP RFO PPA do not best reflect short-term competitive market prices. SCE also offered KRCC and Sycamore the same non-price terms for the Dispatchable Transition Agreements as SCE had agreed to with respect to the comparable Sycamore CHP RFO Agreements. While there are changes between the documents offered, they are (i) generally mutually beneficial and clarify omissions or mistakes in the previous documents, (ii) to conform to the transition period timing or (iii) to update language and concepts in accordance with new tariff provisions. On October 10, 2012, Director Randolph denied KRCC and Sycamore’s request of October 9 for an additional extension, leaving October 15, 2012 as the “final extension.” Meanwhile the parties worked intensively to reach an agreement. The parties agreed on a price of $51.96/kW-year for capacity payments for the dispatchable facilities (with the pricing split between the RA Confirmation and the UC Toll Confirmation for both projects). In addition, the parties agreed on the detailed terms and conditions of both CHP Agreements and Dispatchable Agreements for both facilities. The KRCC and Sycamore Transition Agreements were executed on October 15, 2012.

28

Mr. Alcantar’s letter also made claims insinuating that SCE was not engaging in good faith negotiations during this time. Having attended the negotiation sessions by telephone and in person, the IE’s assessment is that SCE acted in good faith.

14

Since KRCC and Sycamore are affiliates of SCE, SCE will be submitting the KRCC Transition Agreements and Sycamore Transition Agreements unredacted with its advice letter filing with the CPUC. This is required under CPUC Decision 06-06-066 (2006) and Appendix 1 thereto, which treats contracts between an IOU and its affiliates as public documents. The parties have also be jointly submitting the unredacted contracts with FERC as part of the Section 205 application.

III.

The Role of the Independent Evaluator

A. The Requirement for an Independent Evaluator The Settlement Agreement does not, by its own terms, require that a Transition PPA between an IOU and a CHP facility require the use of an Independent Evaluator.29 However, since KRCC and Sycamore, affiliates of SCE, sought to negotiate a Transition PPA, SCE determined to use an IE in accordance with CPUC policy and practice. The role of IEs in California IOU procurement processes has evolved over the years. In 2004, the CPUC initially required the use of an IE by IOUs in resource solicitations where there is an affiliated offeror (or offerors) or where the utility proposed to build a project under a turnkey contract that would ultimately be owned by the utility.30 The CPUC generally endorsed the guidelines issued by FERC for independent evaluation where an affiliate of the purchaser is a bidder in a competitive solicitation, but stated that the role of the IE would not be to make binding decisions on behalf of the utilities or administer the entire process.31 Instead, the IE would be consulted by the IOU, along with the Procurement Review Group (“PRG”) on the design, administration, and evaluation aspects of the Request for Proposals (“RFP”) and issue a report on his/her findings. The CPUC decision indicated that IEs must be independent and free of conflicts of interest, have technical expertise and experience in the evaluation of power products, and be familiar with industry contracts and practices. From a process standpoint, the IOU could contract directly with the IE in consultation with its PRG, but the IE would coordinate with the Energy Division. In 2006, the CPUC required each IOU to retain an IE regarding all RFPs issued pursuant to the RPS, regardless of whether there would be any utility-owned or affiliate-owned projects under 29

With respect to bilaterally negotiated PPAs under Section 4.3 of the Settlement Agreement, the use of an IE is required for any negotiations between an IOU and its affiliate and may be used at the election of either the BuyerIOU or seller in other negotiations.

30

D.04-12-048 (December 16, 2004). Decision 04-12-048 at 129-37. The FERC guidelines are set forth in Ameren Energy Generating Company, 108 FERC ¶ 61,081 (June 29, 2004).

31

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consideration.32 This was extended to any long-term contract for new generation.33 In addition, the CPUC directed the IE for each RFP to provide reports on the entire bid, solicitation, evaluation and selection process. In 2007, the use of an IE was required for any competitive RFO seeking products for a term of three months or more.34 Moreover, the process for retaining IEs was substantially modified, with IOUs developing a pool of qualified IEs, subject to feedback and any recommendations from the IOU’s PRG and the Energy Division, an interview process for IE candidates, and final approval of IEs by the Energy Division.35 In 2008, the CPUC changed the minimum term requirement from three months to two years, and reiterated that an IE must be utilized whenever an affiliate or utility bidder participates in the RFO, regardless of contract duration.36 In 2009, the CPUC required that bilateral RPS contracts should be reviewed according to the same processes and standards as contracts that come through a solicitation, including review by a utility’s PRG and its IE, including a report filed by the IE.37 The CPUC’s affiliate transaction rules generally require that any power purchase contract between a regulated IOU and an unregulated affiliate is subject to its approval.38 SCE’s compliance plan regarding the affiliate transaction rules requires the use of an Independent Evaluator for the solicitation of new or repowered generation resources where an affiliate is a participant.39 While it may not be clear that CPUC rules or SCE’s affiliate transaction rules compliance plan required the use of an IE to monitor negotiations between SCE and an affiliated owner of an existing facility in the context of a Transition PPA, SCE decided to retain an IE to do so, which, at a minimum, appears consistent with CPUC and FERC policy. Beginning with the Edgar case in 1991, the Federal Energy Regulatory Commission has required that a seller of wholesale electric power making a sale to an affiliated regulated utility for resale at market-based rates must demonstrate that the rates and other terms and conditions of the power sales contract are not unduly preferential to the affiliate.40 In subsequent cases involving affiliated sellers who obtained contracts resulting from a purchasing utility’s competitive procurement process, one of FERC’s guidelines for utility conduct of procurement processes to protect against preference toward an affiliate is oversight by an independent third party.41 While the nature of a standard Transition PPA and negotiated Transition Dispatchable Agreements are different from a competitive solicitation pursuant to which suppliers and market prices would be determined, the underlying concern is similar, i.e., to ensure that affiliates are treated in a nonpreferential manner so that prices ultimately paid by captive retail customers are not unduly high as a consequence. An independent third party monitoring the negotiation process involving both 32

Decision 06-05-039 (May 25, 2006). Decision 06-07-029 (July 21, 2006). 34 Decision 07-12-52 (December 21, 2007) at 140. 35 Id. at 136-140. 36 Decision 08-11-008 (November 10, 2008) at 26-27, 40. 37 Decision 09-06-050 (June 18, 2009). 38 Decision 06-12-029 (December 20, 2006) adopting revised affiliate transaction rules, Appendix A-3, Rule III.B.1. 39 SCE 2012 Affiliate Transaction Rules Compliance Plan, Advice Letter 2750-E dated June 27, 2012 (approved July 26, 2012), pp. 13, E-7, E-8. 40 Boston Edison Electric Co: Re: Edgar Electric Energy Co., 55 FERC ¶ 61,382 (1991) (“Edgar”). 41 Allegheny Electric Supply Company, LLC, 108 FERC ¶ 61,082 (2004). See also San Diego Gas & Electric Company, 135 FERC ¶ 61,257 (2011). 33

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standard and negotiated contracts, including a negotiated price for the dispatchable capacity and modifications to the standard contracts, can assist the FERC and the CPUC in determining whether an affiliate has been given preferential treatment.

B. The Role Played by the Independent Evaluator With Respect to the KRCC and Sycamore Transition PPAs In July 2011, Merrimack Energy was retained by SCE to serve as Independent Evaluator for the first CHP RFO to be conducted pursuant to the Settlement Agreement.42 In addition, Merrimack Energy was subsequently retained to serve as IE for contract negotiations that SCE might conduct with affiliates pursuant to the Settlement Agreement, regardless of whether the contracts were associated with offers made in the RFO. An initial meeting regarding a Transition PPA between SCE, on the one hand, and KRCC and Sycamore, on the other took place on August 9, 2011 by conference call, with the IE present. During numerous conference calls that took place over the next 15 months, the IE monitored the negotiations either in person or by telephone. Face-to-face meetings negotiation sessions did not occur until the mediation session on September 12, 2012 and a detailed negotiation session at SCE’s offices on October 10, 2012. Following SCE’s short listing of KRCC’s and Sycamore’s offers in the CHP RFO in March 2012 and through SCE’s conclusion of agreements with Sycamore and subsequent amendments in August 2012, the IE monitored numerous contract negotiation sessions between SCE and Sycamore in the CHP RFO.43 During this period, Sycamore and KRCC’s chief negotiators were Chevron employees with responsibility for the projects, rather than those of Edison Mission, SCE’s affiliate. During the early stages of the negotiations between SCE and its affiliates for Transition PPAs, the IE raised the question to SCE and KRCC and Sycamore as to whether KRCC and Sycamore might be “slow walking” the process for entry into a Transition PPA. It is the IE’s understanding that the terms of KRCC’s and Sycamore’s then-existing PPAs (the Legacy PPAs) were more favorable to KRCC and Sycamore and less favorable to SCE and its ratepayers than the terms of a Transition PPA. While the pricing for the baseload capacity for both projects under the Standard Transition PPA is the same as under the Legacy PPAs, the availability adjustment/penalty provisions associated with firm capacity payments are more rigorous under the Transition PPA than under the prior agreements (95 percent availability is required to receive full capacity payments instead of 80 percent availability), which would likely result in lower 42

Merrimack Energy was retained by SCE out of a pool of Independent Evaluators previously approved by SCE and the Energy Division consistent with the process set forth by the CPUC in Decision 07-12-052 (pp. 136-142). In June 2012, PG&E had retained Merrimack Energy to serve as its IE for its first CHP RFO under the Settlement Agreement. To address logistical and confidentiality issues, it was agreed that Barry Sheingold, President of NEO, Merrimack Energy’s subcontractor, would serve as the lead IE for SCE, while Wayne Oliver, Principal of Merrimack Energy, would serve as IE for PG&E. 43 After SCE short listed KRCC, KRCC withdrew its offer.

17

payments under a Transition PPA. More importantly, for KRCC, it was highly likely that capacity payments for the two dispatchable generating units under a Transition Agreement would be substantially lower than the $91.97/kW-year that KRCC was receiving under its Legacy PPA. Finally, from SCE’s perspective, transitioning two Sycamore generating units from baseload operation to dispatchable operation would result in avoiding the payment of above-market energy costs to Sycamore, based on SCE’s market valuation. KRCC and Sycamore, on the other hand, wanted to keep the two KRCC units operating as dispatchable units and wanted to move two of the Sycamore units from baseload to dispatchable operation. The primary outstanding issues were capacity pricing for the dispatchable units and the timing and process for moving KRCC and Sycamore from the Legacy PPAs to Transition Agreements. When Watson and KRCC/Sycamore initially asked the CPUC’s Energy Division for an extension of time to negotiate a form of Transition PPA without any time limitation, the IE suggested to SCE that there should be some reasonable end date for any extension. SCE proposed such a time limitation to the Energy Division, which Energy Division approved. After SCE responded to KRCC/Sycamore in March 2012 that the sellers’ proposed price for dispatchable capacity was not a competitive market price, the IE requested that SCE provide its valuation of the offer. The information provided by SCE to the IE indicated that KRCC/Sycamore’s proposed capacity pricing was considerably in excess of SCE’s market forecast, which was extrapolated based on market transactions SCE had entered into in previous All Source RFOs.44 Subsequently, the IE suggested to SCE that it make a counter-offer to KRCC/Sycamore based on SCE’s view as to what an appropriate “competitive market price” would be for KRCC and Sycamore. SCE declined to do so for a number of reasons, stating that it was inappropriate to make counter-offers to sellers as a general matter because it could indirectly disclose market transactional information, vendor forecasts, or the company’s own market forecasts, all of which are treated by the company as confidential information. Moreover, there was particular sensitivity in making a counter-offer in the middle of a competitive solicitation with participants in the solicitation, especially where the participants are affiliates, because it might provide, or be perceived as providing, a competitive advantage to them. Ultimately, however, via the mediation session, SCE did engage in negotiating over price with KRCC/Sycamore, which provided the foundation for the agreed-upon contract price.45 Following the mediation session and in the week preceding the final execution of the Transition Agreements, the parties verbally agreed on pricing for the dispatchable units. As mentioned previously, the parties had different interpretations regarding appropriate pricing for the dispatchable units under the Settlement Agreement for the Transition Period. The only generating facilities for which this was an issue were SCE affiliates—KRCC, Sycamore, and Watson. Hence, one could not compare how SCE treated affiliated generators to similarly situated non-affiliated generators, because there were none. The IE focused on whether SCE’s interpretation of the Settlement Agreement was reasonable and not unduly preferential toward its affiliates. SCE’s interpretation was the most favorable to its ratepayers and against the interest 44

SCE’s valuation and the basis for it are described in the Confidential Appendix to this report. While the IE monitored the mediation session and the associated price negotiations, SCE did not consult with the IE regarding its approach to pricing before engaging in these negotiations.

45

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of its affiliates, was reasonable, and, in the IE’s opinion, consistent with the Settlement Agreement. Another matter raised by the IE with SCE is what are the appropriate questions to ask with respect to proposed contract changes sought by affiliates in the context of contract negotiations. The general standard, in our experience, is that the utility should treat an affiliate no more favorably than a non-affiliated party similarly situated. However, in many situations there are no non-affiliated counterparties who are “similarly situated.” During discussions with SCE in the context of the CHP RFO, the IE suggested that the following questions would be appropriate for SCE to consider. A. Is the affiliate using the appropriate pro forma contract as the basis for seeking changes consistent with SCE standards/policies? B. Are the proposed changes to contract terms by an affiliate in the context of a pro forma contract that SCE generally treats as being negotiable or non-negotiable? C. If negotiable, what are the general standards/policies by which SCE considers proposed changes to the applicable pro forma contract? D. Would accepting the proposed changes to the pro forma contract be consistent with SCE’s general standards/policies regarding changes to the applicable pro forma contract? Would it involve SCE asking for other changes that would be beneficial to SCE? If so, what are the applicable standards/policies? E. What are the reasons given by the affiliated seller for the proposed change? What is SCE’s reason for granting it? If SCE accepts the proposed change in concept, but seeks to negotiate the particular provision, what is SCE’s plan for doing so? What is the result? F. Would accepting any proposed change to a pro forma contract constitute any nonconformity with respect to any provision of the Settlement Agreement or the RFO instructions? G. Are there any non-affiliated projects that have similar issues or have sought similar changes? If so, has SCE treated the affiliated projects similarly to non-affiliated projects? H. If the issues or suggested changes are not similar to those involving non-affiliated projects, how is the approach taken with affiliated projects not preferential when compared with the approach taken with respect to proposed changes sought by nonaffiliated projects? I. Do the proposed changes affect the value of the project proposal to SCE? If so, (a) how, and (b) are the proposed changes being appropriately taken into consideration in the quantitative and/or qualitative evaluation? 19

J. Are the changes requested by affiliates more extensive or affect risk allocation more than those sought by non-affiliates? Are the changes granted by SCE to affiliates more extensive or affect risk allocation more than those granted to non-affiliates? If so, what are the justifications? K. Are the changes to the pro forma contract for the affiliated project beneficial, neutral or negative to SCE customers as a whole taking into consideration the nature of the issues raised by the affiliated offeror, the affiliated offeror’s project, and the affiliated offeror’s proposal? L. Do the change(s) to the pro forma contract provide a benefit to the affiliated seller that non-affiliated sellers do not receive? If so, what is the justification for allowing the change?46 The IE asked SCE to explain its reasons for agreeing to or not agreeing to changes proposed by KRCC/Sycamore. More specifically, since SCE had already negotiated CHP RFO Agreements with Sycamore, the parties agreed to use those agreements as the basis for the KRCC and Sycamore Transition Agreements. The IE found this acceptable, since the IE had monitored and found reasonable and not preferential the terms and conditions of the CHP RFO agreements. The IE monitored the contract negotiations and reviewed the changes from the CHP RFO agreements in terms of their reasonableness and appropriateness. In addition to monitoring negotiations to assure SCE did not treat KRCC and Sycamore in a preferential manner, the IE performed oversight to assure that KRCC and Sycamore were being treated fairly and that SCE was acting reasonably in accordance with the Settlement Agreement. There were sharp disagreements between the parties regarding interpretation of the Settlement Agreement on a number of issues, and the Energy Division Director resolved some of them. There were a number of instances where the Settlement Agreement may not have been very clear and there has been a need for interpretation. While it is not the IE’s role to determine the meaning of the Settlement Agreement (the IE is not acting as an arbitrator), the IE reviewed in a variety of contexts SCE’s interpretation of the Settlement Agreement for reasonableness and whether SCE’s actions were in accord with the Settlement Agreement reasonably interpreted.

46

These questions were posed to SCE in the context of the CHP RFO (as well as the negotiations with affiliates for Transition PPAs). As such, not all the questions are relevant to the Transition PPA negotiations.

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IV.

Reasonableness of Pricing, Fairness and Reasonableness of SCE’s Conduct of the Negotiations and Whether SCE Treated KRCC and Sycamore, Its Affiliates, in a NonPreferential Manner

A. Introduction Over the past several years, the CPUC’s Energy Division has developed templates for Independent Evaluator reports for competitive procurement processes. Some of the matters ordinarily addressed in these reports are relevant in the context of an IE report addressing an IOU’s negotiation of modifications to a standard contract with an affiliate. 1. Describe in detail the role of the IE in the procurement process; 2. Describe the reasonableness and fairness of the utility’s conduct of the process; 3. Describe the utility’s contract-specific negotiations; highlight any areas of concern regarding contract provisions; 4. Describe, as applicable, any safeguards and methodologies employed by the utility to assure that affiliated counterparties are treated in a non-preferential fashion; 5. Based on the information available, does the contract merit Commission approval? Other matters ordinarily addressed in IE reports applicable to solicitations are not relevant here.47 In determining whether affiliates have been treated in a non-preferential manner with regard to prices in negotiated agreements outside the context of a competitive solicitation, the FERC has identified two sources of information applicable to FERC’s review: 1. Prices which nonaffiliated buyers were willing to pay for similar services from the sellerapplicants; and 2. Benchmark evidence which shows the price, the terms, and conditions of sales made by nonaffiliated sellers in the relevant market.48 Since there is no evidence of what nonaffiliated buyers were willing to pay for dispatchable capacity to KRCC or Sycamore for a similar 1-3 year term, the relevant information, from the standpoint of FERC’s review, is benchmark evidence. FERC has indicated that: “Two major considerations with respect to the credibility of benchmark evidence would be whether the benchmark sales are contemporaneous and whether they are for similar services when compared 47

Examples are: adequacy of outreach to prospective bidders, the robustness of a solicitation, the strengths and weaknesses of the solicitation evaluation framework, the reasonableness and consistency of the application of the evaluation framework to offers, and whether the contract under consideration represents the best overall offer(s) received by the utility. 48 Boston Edison Company Re: Edgar Electric Energy Company, 55 FERC¶61,382 (1991) (“Edgar”).

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to the instant transaction.”49 An important question is whether benchmark evidence supports the $51.96/kW-year pricing for the KRCC and Sycamore dispatchable facilities under the Transition Agreements. The FERC has articulated four guidelines applicable to affiliate offers selected and contracts negotiated in the context of a competitive solicitation: 1. Transparency of the process; 2. Precise definition of products sought; 3. Standardized evaluation criteria equally applied; 50 4. Oversight by an independent third party. Since the agreements under review here are standard contracts for baseload CHP capacity that is the product of a state commission-approved settlement agreement along with negotiated prices for dispatchable capacity, this report will focus on the FERC guidelines in this context.

B. KRCC and Sycamore’s Eligibility for, and Compliance With, the Standard Transition PPA for Baseload Capacity and Its Right to Contracts for Dispatchable Capacity for the Transition Period As indicated previously, a CHP facility owner with a Legacy PPA that has been under an extension is entitled to sign a Transition PPA under the Settlement Agreement with the same IOU-Buyer.51 Both KRCC and Sycamore have such an “Extension PPA” (as ordered by the CPUC in D.07-09-040). The Settlement provides that the “capacity and energy that the CHP facility may sell to the IOU under the Transition PPA are limited to an amount consistent with the QF’s historical deliveries under its Legacy PPA, but energy delivery may be lower upon the election of the Seller.”52 In terms of determining the limit with respect to capacity sales, SCE compared net contract capacity amounts under the Transition PPAs and Transition Tolling Confirmations to the firm contract amounts under the Legacy PPAs. Under the letter agreement between SCE and Sycamore dated June 17, 2008 (“Sycamore PPA Extension”), the firm capacity sold by Sycamore under the PPA Extension is 300 MW—300,000 kW. Sycamore’s Net Contract Capacity under the Transition PPA is 152,000 kW in each month. Under the Sycamore Transition Tolling Confirmation, the monthly contract capacity for two units combined is 148 MW (the same is it is under the Sycamore Transition RA Confirmation). 49

Edgar, 55 FERC¶61,382, 62,169. Allegheny Electric Supply Company, LLC, 108 FERC ¶ 61,082 (2004). See also San Diego Gas & Electric Company, 135 FERC ¶ 61,257 (2011). 51 Settlement Agreement § 3.1.1. 52 Settlement Agreement § 3.1.3. 50

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The total of the net contract capacity under the Sycamore Transition Agreements is equal to the 300 MW of firm contract capacity under the Sycamore Legacy PPA. Under KRCC’s 2005 PPA with SCE, extended pursuant to a June 28, 2011 letter agreement, the base load net contract capacity is 147,500 kW and the dispatch net contract capacity is 148,500 kW in the summer months (June-September) and 156,000 kW in the winter months (all other months). The total winter capacity is 303,500 kW. SCE compared this to the sum of the Net Contract Capacity under the KCC Transition PPA of 154,000 kW in each month and the contract quantity of under the KRCC Transition Tolling Confirmation of 148 MW—a total of 302,000 kW, which is equal to or lower than the amount of firm contract capacity under the KRCC Legacy PPA.53 Under Section 1.02(e) of the KRCC Transition PPA, the expected annual energy deliveries are 1,280,000 MWh, and subject to allowed changes for certain facility modifications or based on changes on site host electrical load or thermal requirements, annual energy deliveries may never exceed 1,280,000 MWh. This amount of annual MWh is somewhat less than what SCE has considered to be KRCC’s historical deliveries under its Extension PPA.54 Under Section 1.02(e) of the Sycamore Transition PPA, the expected annual energy deliveries are 1,280,000 MWh, and subject to allowed changes for certain facility modifications or based on changes on site host electrical load or thermal requirements, annual energy deliveries may never exceed 1,280,000 MWh. This amount of annual MWh is much less than Sycamore’s historical deliveries under its Legacy PPA since all four generating units have been operating in baseload mode while two of those units will be converting to dispatchable operation and are expected to have low capacity factors due to their high heat rates. The Standard Transition PPA provides for the insertion of project specific information in the Transition PPA, specifically: 1. 2. 3. 4. 5. 6. 7. 8.

The identity of the Seller and the date of execution of the Transition PPA (Preamble); The name of the Existing PPA and the term of the Transition PPA (Section 1.01); The specific generation facility name (Section 1.02(a)); Generating facility description (Exhibit B); Generating facility location (Section 1.02(b)); Cogeneration facility type (Section 1.02(c)); Amount of monthly firm and as-available capacity (Section 1.02(d)); Expected annual energy production and cap (Section 1.02(e);

53

The amount of contract capacity under the KRCC Transition RA Confirmation is 154 MW for a total of 308,000 kW, but SCE used the amount of capacity under the Transition Tolling Confirmation to assess the contract capacity limit for purposes of the Settlement Agreement. If one took an average of the RA Confirmation and UC Toll Confirmation kW weight-averaged by price and added that to the 154,000 kW of net contract capacity under the KRCC Transition PPA, the total capacity is 303,635 kW, which is substantially identical to the 303,500 kW of contract capacity under the Legacy PPA. 54 For purposes of maximum Expected Term Year Energy Production under Section 1.02(e), SCE uses the highest of the last four years of energy deliveries, which, in KRCC’s case, was in 2010.

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9. Scheduling Coordinator election (Section 1.08). The information applicable to KRCC and the KRCC Project was incorporated in the KRCC Transition PPA. The information applicable to Sycamore and the Sycamore Project was incorporated in the Sycamore Transition PPA. Under the Transition PPA, the Seller may, subject to limitations, elect the term, amount and type of contract capacity to be sold, and expected energy production. KRCC and Sycamore made the elections they were entitled to make and these were incorporated in the KRCC and Sycamore Transition PPAs.55 The KRCC Transition PPA is practically identical to the Sycamore Transition PPA with a few project-specific exceptions: 1. Term: a.

b.

Sycamore: The term ends immediately before the commencement of the Sycamore CHP RFO PPA, but if regulatory approvals for the Sycamore CHP RFO PPA are not obtained prior to June 30, 2014, the term ends on June 30, 2015;56 KRCC: The term ends on June 30, 2015, subject to KRCC’s right to terminate if it has been selected in a competitive solicitation by SCE or another California investor-owned utility or signs a power sales contract with an investor-owned utility other than SCE.57

2. Generating Units a. Sycamore: Sycamore Generating Units 1 and 3 b. KRCC: KRCC Generating Units 2 and 4 3. Contract Capacity: a. Sycamore: Net Contract Capacity is 152,000 kW in each month 1. Monthly Firm Contract Capacity varies from 147,000 kW in July through September to 152,000 kW in December and January; 2. As-Available Contract Capacity varies from 0 kW in December and January to 5,000 kW in July through September. b. KRCC: Net Contract Capacity is 154,000 kW in each month 1. Monthly Firm Contract Capacity varies from 140,000 kW in July to 150,000 kW in January and February; 2. As-Available Contract Capacity varies from 4,000 kW in January and February to 14,000 kW in July. 55

These insertions can be seen in the redline showing the differences between the Standard Transition PPA and the KRCC and Sycamore Transition PPAs, which have been provided by SCE as an appendix in its Advice Letter filing with the CPUC and as an attachment to the applications to the FERC. In addition, provisions that are in the Standard Transition PPA that are applicable to SCE only are included in the KRCC and Sycamore Transition PPAs and those applicable only to the other California IOUs are stricken (see, e.g., Exhibit D, § 3(a) and 4, Exhibit S §1). 56 Sycamore Transition PPA Section 1.01. 57 KRCC Transition PPA Sections 1.01 and 2.02(b). There are similar term-related provisions in the KRCC Transition Dispatchable Agreements: KRCC Transition RA Confirmation Sections 2.4 and 13.2; KRCC Transition UC Toll Confirmation Sections 1.4 and 5.4.

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The Settlement Agreement also provides for the incorporation of “Additional Dispatchable Capacity” into a Transition PPA with a “competitive market price” with terms and conditions for the dispatchable capacity to be negotiated (i.e., there are no standard provisions for the dispatchable capacity). The parties negotiated pricing for the dispatchable capacity as well as applicable terms and conditions.

C. The Sycamore and KRCC Dispatchable Agreements58 Under the Sycamore Transition Dispatchable Agreements, Unit 2 and Unit 4 will be dispatchable for a term that may be as short as six months or so (assuming that performance under the Transition Agreements can commence by July 1, 2013 or so following regulatory approvals and if the Sycamore CHP RFO Agreements are timely approved and performance can commence on January 1, 2014, as planned). The term, however, may be as long as two years (ending June 30, 2015). Under the Sycamore Transition RA Confirmation, Sycamore will provide 74 MW per month of RA contract capacity from each of the two dispatchable units—for a total of 148 MW. The applicable contract price is $1.18/kW-month, which shall be paid to Sycamore, subject to the satisfaction of applicable performance obligations. Sycamore would be paid (subject to the satisfaction of applicable performance obligations) the product of $1.18/kW-month multiplied by 74,000/kW-month. Under Section 12.1 of the RA Confirmation, the Seller, as long as it does not have an investment grade credit rating, is obligated to provide a “Full Floating Independent Amount” equal to 20 percent of the sum of the monthly payments for the current months and for the remaining months of the delivery period.59 This means that this amount is added to SCE’s Exposure to Sycamore, as determined under the UC Toll Confirmation, for purposes of determining Sycamore’s collateral requirement. Under the Sycamore Transition UC Toll Confirmation, the delivery periods for Units 2 and 4 are the same as under the RA Confirmation. For 74 MW of contract capacity for each of these units, SCE would pay Sycamore $3.15/kW-month, subject to reduction if available capacity is less than the contract capacity.60 Payments are to be made based on monthly price shapes. The monthly price shape varies from 10% in the months of February through April to 240% in September, 330% in July, and 405% in August.

58

Terms used in this section, if not previously defined, are defined in the applicable Agreement between KRCC or Sycamore and SCE 59 This methodology is used in the absence of a liquid market for RA Capacity, which, if it materializes, would result in the parties amending the agreement to include a mark-to-market methodology. Sycamore RA Confirmation §12.2. 60 Sycamore UC Toll §3.2.

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When taken together, the sum of the capacity payments under the Transition UC Toll Confirmation and the Transition RA Confirmation are equal to $4.33/kW-month or $51.96/kWyear. Aside from the monthly capacity payment, SCE would make the following payments under the UC Toll: 

 

Fuel charge—generally, the product of: o Kern River delivered natural gas index in $/MMBtu (Platt’s Gas Daily midpoint) plus $0.01/MMBtu; and o The product of (a) delivered energy (MWh) and (b) the contractually specified heat rate, which is 12,300 Btu/kWh at 70 MW declining to 12,000 Btu/kWh at 75 MW and above; Variable O&M charge of $0.23/MWh; Start-up charges ($4,100 per start-up, 235 MMBtu of fuel, and 0.13 MWh of Aux Energy).

SCE is responsible for GHG allowance costs, subject to the conditions and limitations set forth in Article 20 of the Sycamore Transition UC Toll. Key economic terms of the Sycamore Transition Dispatchable Agreements are summarized in the table below. Contract Term

From regulatory approval of the Sycamore Transition Agreements until immediately before the commencement of the term under the Sycamore CHP RFO Agreements, but if regulatory approval is not obtained for the Sycamore CHP RFO Agreements, through June 30, 2015.

RA Total Capacity RA Capacity Flat Price

148 MW (Units 2 & 4) $1.18/kW-month

UC Toll Capacity UC Toll Capacity Price Heat Rate—Minimum Generation Heat Rate—Maximum Generation Variable O&M Charge Fuel cost recovery

148 MW (Units 2 & 4) $3.15/kW-month 12,300 Btu/kWh at 70.0 MW (each unit) 12,000 Btu/kWh at 85.0 MW (each unit) $0.23/MWh Kern River delivered city-gate index + $0.01/MMBtu + start-up charges61

With respect to Sycamore’s collateral obligations under the Sycamore Transition UC Toll, if Sycamore has less than an investment grade credit rating, it will have another Full Floating Independent Amount equal to ten percent of the market value of the transaction (10% of current and future capacity payments for the delivery period). At the same time, there will be a 61

There is also an adder of $.35/MMBtu if SCE requires additional gas beyond the day-ahead quantity. The same is true under the KRCC Transition UC Toll. Due to the magnitude of the adder, it is unlikely that the Sycamore and KRCC dispatchable units would operate economically in the real-time market, which SCE considered in its economic evaluation.

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determination of SCE’s Exposure, based on a mark-to-market calculation, calculated in accordance with Section 15.3 of the UC Toll, which can be positive or negative. Sycamore’s Collateral Requirement is the sum of its Exposure plus the Independent Amounts, but it may not exceed $1.6 million.62 There is no Collateral Requirement for SCE. Under the Sycamore Agreements, the obligations of Sycamore to deliver products and the obligation of SCE to pay for them are subject to obtaining the necessary regulatory approvals from both the CPUC and FERC. With respect to commercial terms, the KRCC Transition PPA is practically identical to the Sycamore Transition PPA with a few project-specific exceptions. Key economic terms of the KRCC Transition Dispatchable Agreements are summarized in the table below. Contract Term

From regulatory approval through June 30, 2015, but may end earlier if KRCC obtains a power contract with a California investor-owned utility and KRCC terminates the KRCC Transition Agreements.63

RA Total Capacity RA Capacity Flat Price

154 MW (Units 1 & 3) $1.18/kW-month

UC Toll Capacity UC Toll Capacity Price Heat Rate—Minimum Generation Heat Rate—Maximum Generation

148 MW (Units 1 & 3) $3.15/kW-month 12,500 Btu/kWh at 70.0 MW (each unit) 12,200 Btu/kWh at 78.0 MW for Unit 1 and at 80.0 MW for Unit 3 $0.23/MWh Kern River delivered city-gate index + $0.01/MMBtu + start-up charges

Variable O&M Charge Fuel cost recovery

Because the expected term of the KRCC Dispatchable Agreements is longer than that of the Sycamore Dispatchable Agreements (approximately two years compared to less than one year), the collateral cap in the KRCC Transition UC Toll Confirmation is larger than that under the Sycamore Transition UC Toll Confirmation--$3.2 million compared to $1.6 million.64 While the language of the Seller’s collateral obligation in the Transition RA Confirmation is identical (Article 12), since the expected term under the KRCC Transition RA Confirmation is longer, Seller’s Full Floating Independent Amount will be larger.

62

Sycamore Transition UC Toll § 15.1, 15.2. KRCC Transition PPA Sections 1.01 and 2.02(b). There are similar term-related provisions in the KRCC Transition Dispatchable Agreements: KRCC Transition RA Confirmation Sections 2.4 and 13.2; KRCC Transition UC Toll Confirmation Sections 1.4 and 5.4. 64 Section 15.1. 63

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D. The Reasonableness of the Pricing Provisions, Especially the Capacity Prices for the Dispatchable Capacity The pricing provisions in the KRCC and Sycamore Transition PPAs (baseload agreements) are identical to those in the Standard Transition PPAs. Since KRCC and Sycamore are entitled to a Transition PPA for the baseload portion of their facilities under the Settlement Agreement, they are entitled to the pricing provisions for the baseload units specified in the Standard Transition PPA. Thus, the pricing provisions for the baseload facilities are clearly appropriate. The pricing for the dispatchable units was negotiated. The parties disagreed on the proper interpretation of the Settlement Agreement. KRCC’s and Sycamore’s interpretation was that capacity pricing should be a competitive price for dispatchable facilities that qualify as CHP facilities under the Settlement Agreement. Since SCE had recently completed a competitive solicitation and had signed agreements with dispatchable facilities, KRCC and Sycamore argued that the price for the KRCC and Sycamore dispatchable units during the Transition Period should be based on the “competitive market price” determined by the SCE CHP RFO. SCE’s interpretation was that the “competitive market price” is for dispatchable generating facilities in the CAISO market, and is not limited to CHP facilities. Moreover, the “competitive market price” is for the nearer-term and shorter-term period Transition Period (until July 1, 2015) and not the seven-year term applicable for existing CHP facilities in the CHP RFO (commencing on or about January 1, 2014). In this section, we review whether the agreed-upon pricing of $51.96/kW-year is consistent with the terms of the Settlement Agreement and whether there is sufficient information to support the pricing as being reasonable and non-preferential. As indicated previously, the IE is not tasked with determining the meaning of the Settlement Agreement. However, the meaning of the Settlement Agreement may be determinative, or at least influential, as to whether the agreedupon pricing is determined to be reasonable and non-preferential by the appropriate regulatory agencies. Initially, the IE agrees with SCE and Director Randolph in his May 31, 2012 letter that Section 3.4.1.2 of the Settlement Agreement applies to Sycamore’s and KRCC’s proposal to enter into agreements with SCE for the Transition Period that incorporate dispatchable capacity. While the language of Section 3.4.1.2 may not be crystal clear and the parties might not have fully thought through some of the procedural aspects of this section, it is the only part of the Settlement Agreement that makes sense with respect to facilities like KRCC and Sycamore and the expressed intent of the Settlement Agreement to move CHP facilities off of their Legacy PPAs on to Transition PPAs or other Subsequent PPAs. A key question is does “competitive market price” mean a competitive market price for dispatchable capacity in the broader CAISO market, including non-CHP facilities, or was it intended to be limited to the market for CHP facilities, as KRCC and Sycamore have argued. We note that while KRCC and Sycamore have requested Director Randolph of the CPUC’s Energy Division to render an opinion on this question, he did not do so. 28

The language of Section 3.4.1.2 refers to “competitive market price” not the competitive market price among CHP dispatchable facilities. If the parties to the Settlement Agreement wanted to limit the market to CHP facilities, they could have written the agreement accordingly. Moreover, the broader market interpretation of “competitive market price” is consistent with the structure of Section 3.4.1.2, which allows Buyer to facilitate an alternative sale of the dispatchable capacity to the CAISO market if it elects not to accept the seller’s pricing offer. If that is the proper interpretation of the Settlement Agreement, what is the benchmark evidence to support the $51.96/kW-year pricing? To answer this question, one must initially focus on the product offered by KRCC and Sycamore under the Transition Dispatchable Agreements. First, they offer RA capacity. Since both projects are located in the Big Creek-Ventura Local RA zone, they provide Local RA as well as System RA. SCE values RA provided in Big Creek-Ventura more highly than ordinary System RA. Second, KRCC and Sycamore offer an energy toll with unit heat rates of approximately 12,300 Btu/kWh. Since the heat rates are high, the capacity value associated with the energy toll is relatively low. However, it is an additional amount to the naked RA value. The term of the offered service is of major importance to the value of the product. For Sycamore, the term of the offered service will likely be very short—the term could commence in July 2013 following regulatory approvals and could end at the end of 2013, assuming that regulatory approvals for the Sycamore CHP Agreements are timely approved so performance under those agreements may commence in January 2014. For KRCC, the term of the Transition Agreements could be for two years assuming a July 2013 commencement date and the term runs through the end of the Transition Period. However, if KRCC enters into a long-term contract arising out of a CHP RFO, the term of the Transition Agreements with SCE could be substantially shorter (KRCC would have the right to terminate the Transition Agreements early).65 Hence, the term for the Transition Agreements is approximately 2013-14 (subject to specified contingencies and seller options). SCE has referenced to the current $67.50/kW-year capacity price under CAISO’s Capacity Procurement Mechanism (“CPM”) and the former $55.00/kW-year CPM price as supporting the $51.96/kW-year KRCC/Sycamore capacity prices. The CPM is a “backstop mechanism” that can be employed by CAISO to “procure capacity to address a deficiency or supplement resource adequacy procurement by load serving entities, as needed, in order to maintain grid reliability.”66 In December 2010, CAISO proposed a CPM price of $55/kW-year for generating units without RA bilateral agreements and that would likely shut down absent support from CAISO. This price was based on 110 percent of the “going forward” costs of a proxy 50 MW combustion turbine. As a result of a negotiated settlement among stakeholders, the CPM price was increased to $67.50/kW-year for 2012 and 2013 (the basis for the “black box” settlement price was not disclosed). 65

See Settlement Agreement Section 3.1.2 and Standard Transition PPA Section 2.02(b). Order on Tariff Revisions, California Independent System Operator Corporation, Docket No. ER11-2256-000 (March 17, 2011).

66

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Neither the proposed nor approved CPM prices are market prices. Moreover, CPM prices would be available to KRCC or Sycamore only if they met specified criteria in the CAISO tariff for capacity that is at risk of retirement and needed for reliability.67 These include: 1. The units are not under bilateral RA agreements; 2. They are needed for reliability purposes by the end of the next RA calendar year; 3. The resource owner has submitted a request for CPM designation attesting that it is uneconomic to remain in service and that the generator will retire without a CPM designation. KRCC/Sycamore have not provided any facts to support potential qualification for CPM pricing or any plan to seek qualification for CPM pricing. The market for capacity prices in California is not highly visible. On the other hand, there is publicly available market information regarding capacity pricing in California. In October 2012, The Brattle Group issued a report on Resource Adequacy in California, in which it characterized RA market prices for existing California generating resources as being “approximately $1838/kW-year (or less)” in the context of “substantial excess capacity.”68 The high end of this range is likely for projects that are in areas with relatively high Local Capacity Requirement needs relative to supply. This is in line with a 2011 CPUC report’s summary of median RA prices for 2009-2011: 1. $18/kW-year for system-only RA (sample of 126 contracts); 2. $31/kW-year for local and system RA in SP26 (sample of 159 contracts); 3. $38/kW-year for local and system RA in NP26 (sample of 82 contracts).69 On October 1, 2012, the City of Palo Alto passed a resolution approving a sale of RA capacity for the May-September period at a price of $2/kW-month.70 Since RA values are higher for summer months when loads are higher, this pricing for system RA is in line with the bottom of the Brattle Group estimate and the 2011 CPUC report data. The location of the KRCC and Sycamore units in the Big Creek-Ventura local RA area in SP26 and the capacity value associated with the energy tolls suggests a value that is toward the higher end of the range posited by the Brattle Group. Both the public and confidential market-based information 67

CAISO Tariff Section 43.2.6. There are other short-term reasons for CPM designation, but they do not appear to be applicable to KRCC and Sycamore. 68 The Brattle Group, “Resource Adequacy in California: Options for Improving Efficiency and Effectiveness,” October 2012, at 1, 3. http://www.brattle.com/_documents/UploadLibrary/Upload1088.pdf. 69 Staff of the CPUC with the Assistance of the California Energy Commission Staff, 2010 Resource Adequacy Report (April 22, 2011) Table 13, p. 24, http://www.cpuc.ca.gov/PUC/energy/Procurement/RA/. The statistics involving tolling/energy value are not included here, since the value is related to the heat rate at which natural gas is converted to electric energy for pricing purposes under specific agreements. The tolling value for high heat rate projects, like KRCC and Sycamore, should be much lower than combined cycle projects with much lower heat rates. Of note, during the negotiations, the parties discussed the lack of public data regarding capacity prices for market transactions. The capacity pricing data in the CPUC report, however, was in the public domain at the time, but the negotiators may not have been aware of it. The IE became aware of the data while preparing this report. 70 http://www.cityofpaloalto.org/civicax/filebank/documents/31605.

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available to the IE suggests a substantially lower market price than the $51.96/kW-year contract price.71 With respect to the FERC application, the burden is on the joint applicants—SCE and KRCC, for the KRCC Transition Agreements, and SCE and Sycamore, for the Sycamore Transition Agreements—to provide benchmark evidence in support of the pricing for the Transition Dispatchable Agreements. If the applicable standard is competitive prices in the CAISO market (not limited to CHP facilities) for Local RA capacity in southern California for 2013-14 with dispatchable energy at 12,000+/Btu/kWh heat rates, the information provided by the joint applicants has been extremely limited—substantially less than what FERC found to be acceptable in Ocean State Power II, 59 FERC ¶ 61,360 (1992).72 If, however, KRCC/Sycamore’s access to the $67.50/kW-year CPM price is considered a probability or at least a strong possibility due to a real threat of shut down of the KRCC and Sycamore facilities, $51.96/kW-year would appear to be a reasonable price. Again, however, the joint applicants have provided no evidence to date in support of a claim that a lower marketbased price would be inadequate for the plants to keep in operation and that the higher agreedupon price is needed to sustain the plants’ operations. In discussions, both parties mentioned IOU contracts with Calpine’s 572 MW Sutter combined cycle generating plants as providing relevant benchmarks (although pricing is confidential). In December 2011, CAISO proposed to procure backstop capacity from the Sutter plant due to Calpine’s stated desire to retire the plant in 2012 and the concern that the plant might not return to commercial operations in future years when it might be needed for reliability purposes. Subsequently, the CPUC ordered the three major IOUs, including SCE, to negotiate a contract with Sutter “in a manner that minimizes the cost to ratepayers”, with the expectation that “in the contract the costs should be significantly below what would be paid if the Sutter plant were subject to the CPM.”73 Calpine was required to provide cash flow models and other detailed financial information to the Energy Division and an IE in connection with the negotiations. Subsequently, SCE and the other IOUs entered into contracts with Sutter. The Sutter contract is for the period July-December 2012, and the pricing was found to satisfy the CPUC’s standard—a price significantly below the CPM price of $67.50/kW-year.74 It is questionable whether the SCE-Sutter contract constitutes a “benchmark market price” since it was a negotiation ordered by the CPUC with the direction that the price be significantly below the $67.50/kW-year CPM benchmark price. More importantly, the impetus for the contract was a CAISO reliability need several years into the future and Calpine’s showing that it would shut down in the absence of a contract with sufficient revenues to support continued operation. Calpine was also required to provide financial information to support its claims of a need for non-market pricing to support maintained operations. These facts are not present here. In fact, 71

Confidential information pertaining to capacity pricing is addressed in the Confidential Appendix to this report. In that case, the applicant provided a benchmark of 33 offers for long-term contracts comparable to the proposed contract. The FERC staff conducted a further review of 10 contracts considered to be the most comparable. 73 Resolution E-4471 (March 29, 2012) at 9. Id. 74 See the CPUC’s May 25, 2012 letter order approving SCE’s Advice Letter 2730-E. 72

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given the long-term contract already executed for the Sycamore facility with an expected operation date of January 2014 and, at least a strong possibility, that the KRCC facility, with its similar economics, will also obtain a long-term contract through the CHP RFO process, it seems implausible that KRCC or Sycamore would seek to retire their facilities.75 Nor does there appear to be a strong need for the KRCC and Sycamore facilities to meet near-term local capacity requirements (“LCRs”). In 2013, there is 5,276 MW of qualifying capacity in the Big Creek/Ventura RA area and a 2013 LCR need of only 2,241 MW.76 The 2013 LCR for Big Creek/Ventura represents a decline of over 850 MW from the 2012 LCR due to a downward trend in load, new transmission projects and load allocation change between substations.77 If the Settlement Agreement’s “competitive market price” is determined to be the competitive market price for CHPs only, then the $51.96/kW-year pricing is more supportable. First, it should be acknowledged that there are relatively few dispatchable CHP projects to determine a “competitive market price” for this market sub-segment, and benchmark pricing for the Transition Period is not visible if it exists at all. SCE’s CHP RFO produced capacity pricing for dispatchable units that is higher than the near term CAISO RA market, including Sycamore’s contract price of $73/kW-year. However, these prices would need to be adjusted downward to be comparable with respect to the Transition Dispatchable Agreements (2013-15) since the term of the CHP RFO Agreements executed by SCE (2014-2020) are expected to start later and, more importantly, would have a much longer term than the Transition PPAs. A downward adjustment suggests a CHP-only market price in the range of the KRCC and Sycamore UPF Transition Agreement pricing.78 In conclusion, the $51.96/kW-year contract price for dispatchable capacity can be supported (1) if CPM pricing (or the contract pricing for the Sutter facility) is determined to be an appropriate benchmark because of a real economic need for this level of capacity pricing to sustain the facilities and to serve a CAISO reliability need or (2) the relevant market for the “competitive market price” is for dispatchable CHP facilities only. However, if (a) the “competitive market price” is not limited to CHPs and (b) CPM (and Sutter contract) pricing is considered not 75

Moreover, two of the four units at each generating facility would be under baseload Transition PPAs at prices SCE considers to be “above market” and the generating facilities also provide steam to Chevron for enhanced oil recovery. Fixed operations and maintenance costs, or at least a substantial portion of them, are likely to be shared among the baseload and dispatchable units at both facilities. Hence, a showing of economic need for a non-market price would involve more complexity than analyzing going forward costs for a single stand-alone generating plant without any contracts. 76 Decision Adopting Local Procurement Obligations for 2013 and Further Refining the Resource Adequacy Program, D 12-06-025 (June 12, 2012) at 8 (the 2013 LCR need is based on Category C with operating procedure). 77 Id. at 7-9. 78 This is addressed in more detail in the Confidential Appendix to this report. It should also be pointed out that one of the issues with this “CHP UPF only” market definition is that SCE-affiliated generators play such a large role in what is a relatively small market. All three generators who have sought Transition Agreements involving dispatchable capacity from SCE are affiliates with a collective nameplate capacity of 981 MW: Watson—385 MW, Sycamore—300 MW, and KRCC—296 MW. This represents 48 percent of the 2,026 MW of CHPs SCE has under existing contracts (although only 3 out of a total of 44, or 7 percent of the projects). However, the universe of CHP projects with dispatchable capacity in the California market is larger, although the IE does not have any specific statistics.

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relevant, there is insufficient benchmark evidence, in the IE’s opinion, to support the contract pricing. Finally, there is one other possibility. The language of the Settlement Agreement could be viewed as being so ambiguous that neither SCE’s or KRCC/Sycamore’s interpretation can be upheld. One could then assess whether the contract price is a reasonable compromise between the “CHP market only” interpretation and the “general market” interpretation. At earlier stages of the negotiations, SCE told KRCC/Sycamore that if the parties could not agree on a “competitive market price,” as SCE interpreted “competitive market price,” SCE would simply offer to facilitate the dispatchable capacity to the CAISO market. However, SCE was concerned that KRCC/Sycamore would continue to apply for, and receive, extensions from the Energy Division, which would extend the operation of the existing Legacy PPAs. In fact, KRCC/Sycamore received five extensions for a total of approximately seven months (March 22, 2012 through October 15, 2012). Under the circumstances, SCE’s decision to engage in negotiations to reach a negotiated settlement with KRCC/Sycamore was reasonable and did not constitute undue preference to its affiliates. According to SCE’s analysis, continued extension of the Legacy PPAs would result in substantial additional costs to ratepayers compared to a negotiated settlement of the dispatchable pricing. If the Sycamore Transition Agreements are approved and go into effect on July 1, 2013 and terminate on December 31, 2013 (assuming the Sycamore CHP RFO Agreements timely receive regulatory approval), the estimated savings for the six-month period are approximately $3.0 million (based on SCE’s assessment). If the KRCC Transition Agreements also go into effect on July 1, 2013 and stay in effect for the entire 24-month term through June 30, 2015, estimated savings are approximately $8.3 million, according to SCE. The total estimated savings for both plants is approximately $11.3 million. While SCE might have negotiated harder for lower capacity payments under the Transition Agreements than the $51.96/kW-year contract price, SCE expressed concern that it might simply have resulted in further deadlock and continued extensions of the Legacy PPAs, with their higher costs to SCE’s customers. However, that is difficult to gauge as the decision whether to grant further extensions was solely up to the Executive Director of the Energy Division. While the dynamics of the negotiations were certainly factors SCE could validly consider in developing and pursuing its negotiation strategy with KRCC/Sycamore, ultimately, the appropriateness of the contract price should rest, in the IE’s opinion, on the interpretation of the Settlement Agreement and the relevance and quality of the supporting benchmark evidence. However, if the Settlement Agreement is determined to be so ambiguous that neither SCE’s nor KRCC/Sycamore’s interpretations can be embraced, SCE’s decision to settle the matter at $51.96/kW-year could be viewed favorably as a reasonable, pragmatic approach to stop the continued effectiveness of the higher-cost Legacy PPAs and replace them with the lower-cost Transition Agreements. One final consideration is the impact on the contractual relationship between SCE and its affiliates, KRCC and Sycamore, if either the CPUC or FERC deny approval. On October 2, 2012, Director Randolph granted a “final extension” to October 15, 2012, and if either KRCC or 33

Sycamore execute a contract with SCE that requires CPUC or FERC approval, an additional extension was granted “until the date when the Subsequent PPA has received the required regulatory approval or denial.” This suggests that if either the CPUC or FERC denies the applications for authorization of the KRCC or Sycamore Transition Agreements, the Legacy PPA for KRCC or Sycamore, as the case may be, terminates with such denial. That would be more equitable than a result that would maintain the Legacy PPAs in effect, in the IE’s opinion.79

E. The Reasonableness of the Non-Pricing Related Terms and Conditions of the Transition PPAs and the Transition Dispatchable Agreements In negotiating the KRCC and Sycamore Transition Agreements, the parties agreed to use the Sycamore CHP RFO UPF Agreements as the basis for negotiations regarding the non-price terms and conditions for the dispatchable capacity and to take into consideration negotiated changes to the Sycamore CHP RFO PPA. The IE concurred that this was a good starting point since the IE had monitored the Sycamore CHP RFO Agreement negotiations, reviewed the contract documents against pertinent pro forma documents, and had concluded in a prior IE report that the terms of the agreements were not the product of preferential treatment by SCE in favor of its affiliate, Sycamore.80 With respect to the Sycamore Agreements, most of the changes to the pro forma provisions of the CHP RFO Pro Forma PPA and the standard UPF Agreements were (a) to incorporate the complex nature of Sycamore’s offer to SCE, such as the transition of Unit 3 over the term of the contracts from predominantly firm capacity, to as-available capacity, and lastly to dispatchable capacity, (b) to incorporate cross-defaults between the Sycamore CHP PPA, the RA Confirmation, and the UC Toll Confirmation, (c) to delete provisions that were inapplicable, such as provisions in the CHP Pro Forma PPA that applied to new or repowered facilities, and (d) to conform different provisions of the applicable agreements, such as dispute resolution, in order to enhance consistency and avoid conflicts. Except for changes for these reasons, SCE generally resisted other proposed changes to the CHP RFO Pro Forma PPA. The Sycamore CHP PPA contains a number of other modifications, but these are relatively minor and are of a nature consistent with modifications made by SCE in other contract negotiations with nonaffiliates.

79

Another alternative could be to allow the Legacy PPAs to terminate unless the parties agree on a contract price for the dispatchable units that more appropriately reflect a “competitive market price.” 80 Report of the Independent Evaluator, Southern California Edison First Combined Heat and Power Request for Offers—Track 1 and Power Purchase Agreement with Sycamore Cogeneration Company (September 2012) (“Sycamore CHP RFO IE Report”) pp. 38-43, attached as Appendix B.1 to Advice 2784-E and Exhibit C to Sycamore’s and SCE’s Request for Request to Make Wholesale Power and Capacity Sales to Affiliate, FERC Docket No. ER13-133-000.

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The original CHP RFO Pro-Forma PPA did not have contract provisions applicable where the seller’s election is that SCE would be responsible for GHG allowance costs (Exhibit S). After reviewing the indicative offers, SCE proposed pro forma provisions for Exhibit S of the CHP PPA, similar to Article 20 of the UC Toll Confirmation, which SCE revised later on in the negotiation process. The modifications to Exhibit S of SCE’s pro forma Exhibit S and Article 20 of the UC Toll Confirmation are relatively modest and similar to, or less involved than, those accepted by SCE in other contract negotiations in the CHP RFO where the counterparty sought modifications. The changes to SCE’s pro forma UPF Documents were also relatively modest other than those modifications associated with incorporating Sycamore’s complex offer and conforming provisions in different agreements for consistency and avoiding conflicts.81 The parties negotiated modifications to the Sycamore CHP RFO Agreements for several reasons: 1. The Standard Transition PPA was used as the standard pro forma agreement for the baseload units instead of the CHP RFO pro forma agreement, as required by the Settlement Agreement; 2. To implement the business terms of the Transition Agreements—e.g., two dispatchable units and two baseload units during the entire term—and a shorter term than the Sycamore CHP RFO Agreements; 3. To take into consideration recent changes in CAISO’s rules regarding RA capacity; 4. Minor clarifications or enhancements to language. Summarized below is a comparison of the Sycamore Transition Agreements to the original pro forma documents. Because the Sycamore Transition PPA is a standard agreement, SCE’s policy regarding changes to these agreements is to allow only project-specific changes of a limited and targeted nature. With regard to the Sycamore Transition Dispatchable Agreements, these agreements are pro forma documents that were not negotiated as part of the Settlement Agreement, such as the Standard Transition PPA. Hence, SCE allowed comparatively more latitude in the negotiation of these agreements, consistent with the company’s practice in the CHP RFO and elsewhere.

Matter Addressed Multi-unit structure of the transaction, term; role of specific generating units

Sycamore Transition PPA Preamble Paragraphs G and H (concurrent entry into Transition EEI Agreement, including Transmission Tolling Confirmation and Transmission RA

Sycamore Transition Dispatchable Agreements RA Confirmation: Section 2.4 (Delivery Period provisions similar to term provisions of Sycamore Transition PPA); Section 2.5 (Contract Quantity of 74 MW each

81

Sycamore CHP RFO IE Report p. 41. The specific modifications to the pro forma documents are summarized at pp. 41-43 of the Sycamore CHP RFO IE Report.

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CPUC and FERC approval of all of the Sycamore Agreements as conditions precedent; the parties’ obligations and rights with respect to CPUC and FERC approval; the relationship between the different agreements

Cross-default provisions CHP Settlement Eligibility

Confirmation); Section 1.01 (Term commences when CPUC Approval and FERC Approval are obtained; the Term End Date is June 30, 2015, but if the CHP RFO Agreements receive regulatory approval, the term will end immediately before the commencement of the term of those agreements); Section 1.02(a) and Exhibit B (Sycamore Generating Units 1 and 3 are the source of supply under this agreement). Section 2.02(e),(f) (if the CPUC and FERC approvals are not obtained or if the Transition UC Toll or RA Confirmation terminates before the delivery period under those agreements, this Agreement terminates; Section 2.04(filing for CPUC approval); Section 2.05 (filing for FERC approval); Section 2.06 (term will not commence until beginning of delivery periods under Transition RA Confirmation and Transition Tolling Confirmation); Exhibit A: Definitions (“CPUC Approval,” “FERC Approval,” and definitions pertaining to the Generating Facility and Generating Units and other Sycamore transition agreements). Section 6.01(a)(vi), (vii).

for Generating Units 2 and 4), Section 5.1(a) (replacement Product may not be delivered from either of the two units subject to the Transition PPA without SCE’s consent in its sole discretion). UC Toll: Section 1.4 (Delivery Period similar to term provisions of Sycamore Transition PPA). EEI Agreement: Section 2.7 (FERC approval as a condition precedent); Section 2.8 (agreement terminates if Transition PPA is terminated before the commencement of the term). RA Confirmation: Sections 2.3 and 8.3(b) (CPUC approval required); Section 8.3(d) (FERC approval required). UC Toll: Section 1.3 (requirement of CPUC and FERC approval); Section 5.2 (agreement re filing for CPUC and FERC approval and consequences of denial).

EEI Agreement: Section 5.1(i), (j). RA Confirmation: Section 8.3(a) (Sycamore represents and warrants that Sycamore is a Qualifying Facility; this transaction is a procurement under the CHP program as contemplated by the Settlement Agreement); Section 8.3(c) (Seller will provide SCE with information required under Settlement Agreement). UC Toll: Section 5.1 (similar to RA Confirmation Section 8.3(a)); Section 5.3 (similar to RA Confirmation Section 8.3(d).

Delivery Point Relation to Settlement Agreement; dispute resolution

Specified in Section 1.03. Section 9.08(o) (Neither party waives any right it may have under the Settlement Agreement).

Compliance with FERC QF requirements

Section 3.17 (Seller is in compliance with the FERC QF requirements— which applies to the entire Generating Facility--if it provides a

EEI Agreement: Section 10.6 (dispute resolution provisions conform with those in Sycamore Transition PPA)

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FERC waiver order to SCE within 5 business days of receipt even if it is after the time set forth in the PPA). Seller requirements; Payment Adjustments

Mark-to-Market Formula in Credit and Collateral Provisions

Greenhouse Gas Emissions Credits

Changes to reflect modifications to the new CAISO RA tariff proposed by CAISO on September 20, 2012 in FERC Docket No. ER-12-2669-000

RA Confirmation: Section 8.1 (Seller shall provide Unit NQC and CAISO Resource ID for units); Article 10 (generating unit substitution). UC Toll: Sections 2.1 and 9.2(a) (ability to dispatch to PMax at CAISO’s instruction subject to operating restrictions); Section 10.2 and Appendix 10.2 (terms regarding testing); Section 12.4 (SCE access); Section 13.1 (standard for Seller operations); Section 13.2 (providing maintenance records from third parties); Section 13.3 (Seller to execute necessary agreements with CAISO). UC Toll: Section 15.3 (uses average of on-peak and off-peak prices for mark-to-market calculations and without 1.2 multiplier, which is applicable for combustion turbine technology in pro forma agreement; uses applicable zonal energy and natural gas prices in formula) UC Toll Section 20.4 (Buyer, rather than Seller, bears GHG Offset Credit invalidation risk if any Offset Credits are invalidated after they are transferred to Buyer, Seller has not transferred such Offset Credits to a third party, and Seller retains title to such invalidated Offset Credits); Section 20.8 (if a change in AB 32 occurs, either party may seek negotiations to make any necessary changes to the Transition UC Toll, but if there is no agreement, either party may invoke dispute resolution). RA Confirmation: Section 1 (Product definition moved to definition section and revised); Sections 2.2 and 2.3 (reflects Seller daily obligation to provide Product); Section 3.1 (reflects Seller daily delivery obligation and obligation to comply with Tariff); Section 3.2— Adjustments to Contract Quantity (revised to reflect Tariff amendments); Section 3.4—PostShowing Replacement Capacity

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Clarification language/minor changes

Section 3.02(a) (“for any portion of the Term” added to clarify that Seller’s obligations regarding RA apply only to the term of this Agreement); Section 6.01(c)(iii) and 9.02(f) (clarifies that it is not an event of default when Seller operates the Generating Facility as directed by the Scheduling Coordinator, CAISO, or the Transmission Provider ); Section 9.01(b) (CPUC approval and FERC authorizations are exceptions to the parties’ covenants regarding regulatory authorizations); 9.09(a)(iii) (adds Buyer’s Cost Allocation Mechanism Group as a party that may receive Confidential Information subject to a protective order), Exhibit A (defined term “Operate” expanded to include “Operating” or “Operation,” a language clarification); Exhibit R— Outage Schedule Submittal Requirements (Schedules to be submitted before “Term Start Date” rather than “Parallel Operation” since Sycamore is an existing facility).

(new section: if CAISO determines need for outage replacement, Seller’s payments will be reduce in accordance with Section 4.1); Section 4.1 (payment formula now provides for potential reduction for Shortfall Capacity and eliminates monthly price shaping); Sections 5.2, 5.3, 8.1, 8.2, 10.1, and Article 13 (conforming changes consistent with new Tariff provisions) EEI Agreement: Section 10.11 (for purposes of confidentiality provision, definition of “Affiliate”). RA Confirmation: Section 3.4 (if CAISO rule changes do not go into effect, there will be no payment reductions for Shortfall Capacity); Article 6 (Buyer, as SC, is liable for its failure to comply with CAISO tariff requirements). UC Toll: Sections 1.5 (Green Attributes/Allowances); Section 3.3 (other events affecting availability); Section 7.1 (RMR contract); Section 8.6 (Buyer, as Scheduling Coordinator, is liable for its failure to comply with CAISO tariff requirements).

Other than project-specific differences previously outlined, the KRCC Transition Dispatchable Agreements are practically identical to the Sycamore Transition PPA with a few exceptions: 

 

As with the KRCC Transition PPA, the Term End Date is June 30, 2015 (Section 1.01), subject to Seller’s right to terminate under Section 2.02(b) if Seller provides at least 90 days notice to SCE, rather than 180 days, as in the Standard Transition PPA, if Seller has entered into an agreement with another California investor-owned utility (KRCC, unlike Sycamore, does not have long-term agreements with SCE arising out of the CHP RFO); Collateral requirements (previously addressed); The requirement in Section 8.1 of the Sycamore Transition RA Confirmation that “Seller shall provide the Unit NQC and CAISO Resource ID for each of the Generating Units 38

subject to the terms and conditions of this Confirmation” is not present in the KRCC Transition RA Confirmation. o The KRCC generating units already have Unit NQC and CAISO Resource IDs since they have been running as separate dispatchable generating units for several years, while the Sycamore units have not been running in that mode and thus far do not have Unit NQC and CAISIO Resource IDs. In the IE’s opinion, the KRCC and Sycamore Transition Agreements were not the product of preference to affiliates. The changes to the Standard Transition PPA were either (a) projectspecific changes or insertions to address the particulars of the overall transaction, such as term, the need for CPUC and FERC approvals (due to requirements applicable to affiliate transactions only), the relationship with the Transition Dispatchable Agreements, including cross-default provisions, and description of the delivery point unique to the KRCC and Sycamore projects or (b) minor changes, primarily language clarification or conforming changes.82 While the changes in the latter category are not strictly project-specific, SCE’s normal standard for making changes in standard agreements, they are not, in the IE’s opinion, material. Like the Transition PPAs, modifications were made to the Transition Dispatchable Agreements from SCE’s pro forma agreements—the EEI Master Agreement, RA Confirmation and Tolling Confirmation—to incorporate terms specific to the nature of the transactions, including term, relationship with Transition PPAs, regulatory approval, cross-default provisions, and CHP Settlement eligibility. There were a variety of changes to the pro forma RA Confirmation to take into consideration impending changes to the CAISO Tariff regarding RA capacity. With the exception of clarifying language suggested by KRCC/Sycamore that would apply if CAISO’s proposed rules do not go into effect, the language modifying the definition of Product, eliminating price shaping, amending the payment calculation in the event SCE replaces RA capacity on behalf of the Seller, and other conforming changes were proposed by SCE, and, according to SCE, will be incorporated in an updated pro forma RA Confirmation (and is being used in other bilateral negotiations, according to SCE). Another change in the RA Confirmation—which would prevent KRCC or Sycamore from replacing a unit under the Transition RA Confirmation with a baseload unit from the same Generating Facility under the Transition PPA—was for SCE’s benefit. The Transition Tolling Confirmations contain several different terms that vary from the pro forma terms. This is in a context where the Standard Transition PPA does not require the Seller to provide any collateral and the Settlement Agreement is silent regarding any collateral requirements associated with dispatchable capacity in a Transition Agreement. The parties agreed to a cap on the collateral requirement, an independent amount equal to 10% of the market value of the transaction, and variations to the mark-to-market formula used in calculating Seller’s collateral requirements (using off-peak, as well as on-peak, forward energy prices in calculating exposure and not using the 1.20 multiplier applicable to combustion turbine technology). This formulation and the collateral caps were based on the negotiated terms of the Sycamore CHP 82

These are summarized in the table above under the column “Sycamore Transition PPA and across from the headings “Relation to Settlement Agreement; dispute resolution,” Compliance with FERC QF Requirements,” and “Clarification language/minor changes.”

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RFO Agreements, with the collateral caps adjusted to take into consideration the shorter duration of the Transition Agreements. Taken as a whole, these credit and collateral terms are reasonable and not unduly preferential to the affiliated generators. The provisions on cost allocation regarding compliance with Greenhouse Gas Emissions regulations (Article 20 of the Tolling Confirmation) are identical to those in the Sycamore CHP RFO Tolling Confirmation. Significant modifications to the pro forma provisions—pertaining to invalidation of Offset Credits and changes in California’s pertinent legislation, AB 32—are summarized in the table above. The modifications to the pro forma provisions are, and were, relatively modest, and this IE considered them to be reasonable and non-preferential to Sycamore in the context of the CHP RFO, which included SCE negotiations with non-affiliated generators. In conclusion, the non-price contractual terms and conditions negotiated by SCE were reasonable and not, in the IE’s opinion, the product of preferential treatment by SCE toward its affiliated generators.

F. SCE’s Internal Mechanisms to Review the KRCC/Sycamore Transition Agreements

SCE has internal systems in place for the review of contracts with affiliates, which were utilized with respect to the decision to enter into the KRCC and Sycamore Transition Agreements. The first, which applies to PPAs with both affiliated and non-affiliated counterparties, is review and approval of PPAs by SCE’s Energy Procurement Risk Management Committee (“RMC”). Second, SCE’s affiliate compliance officer, Akbar Jazayeri, Vice President, Regulatory Operations, participated in the review and approval of the KRCC and Sycamore Transition Agreements to assure compliance by SCE of its obligations under the CPUC’s Affiliate Transaction Rules. On October 12, 2012, SCE’s RMC approved SCE’s entry into the Transition Agreements with KRCC and Sycamore and SCE’s Cost Allocation Mechanism (“CAM”) Group was consulted regarding the transactions before the agreements were executed on October 15, 2012. SCE entered into the KRCC and Sycamore Transition Agreements following utilization of its internal procedures applicable to contracts with affiliated generators.

G. Consistency With FERC Principles 1. Edgar Analysis In the 1991 Edgar decision, FERC determined that where a utility is proposing to purchase power from an affiliated seller at market-based rates it must provide evidence of non-preferential treatment either through the results of a competitive bidding process, benchmark evidence of contemporaneous offers or market transactions, or what non-affiliated buyers were willing to 40

pay. Here, the Standard Transition PPA (including the rates, rate formulas, and contract terms incorporated in the Transition PPA) was negotiated by the major California utility buyers, CHP seller interests and ratepayer advocates in the context of the CHP Settlement and approved by the CPUC. Eligible parties under the CHP Settlement, including SCE’s affiliates, KRCC and Sycamore, are entitled to sell under the Standard Transition PPA and the buyers under the Legacy PPAs from these eligible sellers are required to purchase. Hence, one can view the Standard Transition PPA as the appropriate “benchmark” in the context of the Edgar decision with regard to baseload CHP sale prices from eligible sellers during the Transition Period. As indicated in Section IV.D of this report, the IE has more serious concerns regarding the benchmark evidence to support the negotiated price for the dispatchable capacity. Whether the negotiated price can be supported by benchmark evidence depends on (a) the interpretation of the Settlement Agreement of what is a “competitive market price” and (b) whether the CAISO’s CPM price or the price negotiated by SCE for the Sutter project are appropriate benchmarks for a “competitive market price.” Also relevant to the inquiry is whether the terms and conditions of the Transition Agreements, including the modifications from the Standard Transition PPA and the pro forma Dispatchable Agreements, are reasonable and not unduly preferential to SCE’s affiliated generators. As indicated in Section IV.E of this report, the IE’s assessment is that SCE negotiated the agreements in a reasonable manner and the agreements are not unduly preferential to KRCC and Sycamore. Since 2004, when FERC issued its Allegheny decision, FERC has identified four principles to guide its evaluation as to whether an affiliate has received an undue preference from a utility in the context of a competitive solicitation:    

Transparency—openness and fairness of the process; Definition—products sought should be precisely defined; Evaluation—evaluation criteria are clear and applied equally to all applicants/offerors; Oversight by an independent third party.

While the bilaterally negotiated modification of a “hybrid” standardized Transition PPA under a Settlement Agreement approved by applicable regulatory authorities and agreement for dispatchable capacity is obviously not the same as a competitive solicitation, it is useful to address SCE’s conduct in the context of the four aforementioned principles. 2. Transparency The CHP Settlement provided for Transition PPAs as an option for owners of California CHP facilities with expired or expiring PURPA contracts during the Transition Period. Shortly after receipt of the FERC’s authorization in June 2011, a prerequisite for the effectiveness of the Settlement Agreement, SCE notified all of its counterparties to QF contracts that it would hold a meeting for members of the QF community on the CHP Settlement to provide information on how they would be impacted by the Settlement Agreement. The meeting was held on July 22, 2011, and it was made available on WebEx. According to SCE, approximately 20 persons 41

attended in person, with an additional 40-some participants attending by WebEx (including the IE). SCE’s presentation was placed on a portion of its website dedicated to the CHP Settlement.83 SCE also included a Transition PPA application on its website. In addition, SCE solicited questions from interested parties regarding the Settlement Agreement and provided the questions and written answers on its website. Soon after the Settlement Agreement became effective, SCE notified its QF counterparties of the effectiveness of the Settlement and their available options. SCE contract managers also informed QF counterparties of options, deadlines, and requirements under the Settlement Agreement. SCE made the Transition PPA available to all eligible parties and did so in an open and fair manner. The Transition PPA (and its terms) was the product of negotiations, as part of an overall settlement, involving all three of the major California investor-owned utilities, several active California QF advocacy groups, and California ratepayer representatives and was approved by the CPUC through a regulatory process that allowed for substantial input from interested parties. The firm capacity prices in the Standard Transition PPA had themselves been authorized by the CPUC in a 2007 decision. The formulaic energy prices were the product of the statewide negotiation process and approved by the CPUC. With regard to “hybrid” baseload and dispatchable generating facilities, the Settlement Agreement provided for a mechanism by which CHP facilities, including existing dispatchable facilities and traditional baseload CHPs which desired to become dispatcahble, could negotiate agreements for dispatchable capacity at a “competitive market price.” The Settlement Agreement is a public document and is posted on SCE’s website.84 3. Product Definition The Standard Transition PPA defines specifically the products that an eligible party may seek to sell to an IOU and the applicable term of the sale. The Settlement Agreement also provides a mechanism for Transition Agreements to include contract provisions for dispatchable capacity. 4. Evaluation Criteria Another principle FERC has applied in the competitive solicitation context is that evaluation criteria should be clearly described and should be applied equally to prospective bidders. In the context of the Standard Transition PPA, eligibility for a Standard Transition PPA is clearly defined in the Settlement Agreement. SCE’s general policy regarding contract modifications to standard contracts is that it considers project-specific modifications but not modifications to generally applicable contract provisions. SCE did not make any public statements regarding this policy to prospective applicants for 83

SCE’s web page on the CHP Settlement is http://www.sce.com/EnergyProcurement/renewables/chp/chpsettlement.htm. The July 2011 SCE presentation is at http://asset.sce.com/Documents/Environment%20%20Renewable%20Energy/QF_CHP_SettlementOverview_MeetingPresentation.pdf. 84

http://www.sce.com/EnergyProcurement/renewables/chp/chp-settlement.htm.

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standard contracts under the Settlement Agreement. In the future, it would be better if SCE were to state its policy on contract modifications publicly.85 However, based on our discussions with SCE, SCE did articulate its policy regarding modifications to standard contracts to any applicant that sought any contract modification, an approach SCE has taken in past procurements involving standard contracts. Finally, we note that policy regarding contract negotiations is a different matter from describing evaluation criteria in a competitive solicitation. 5. Oversight Prior to the effective date of the Settlement Agreement, SCE retained Merrimack Energy to serve as IE for the first CHP RFO it would issue and for negotiations with affiliates under Transition PPAs. Once SCE heard from KRCC/Sycamore that KRCC/Sycamore planned to negotiate a Transition PPA, especially one with additional dispatchable capacity, SCE engaged Merrimack to monitor those negotiations. Barry Sheingold, President of New Energy Opportunities, Inc., Merrimack Energy’s subcontractor, monitored all of the negotiations between SCE and KRCC/Sycamore pertaining to the Transition PPA. Mr. Sheingold’s assessment is that SCE negotiated vigorously with KRCC/Sycamore for the most part. There was no competitive solicitation which resulted in the Standard Transition PPA or in the KRCC and Sycamore Transition Agreements, so the FERC requirement for IE oversight of the design of a solicitation should not be applicable here. However, there was ample involvement of other utilities, market participants, and ratepayer advocates in the process of structuring the Standard Transition PPA, as well as CPUC approval, so there was a form of oversight in place at that time.

V.

Conclusion: Do the Contracts Merit Commission Approval?

The key issues addressed in this report are whether the pricing and other terms and conditions of the Sycamore and KRCC Transition Agreements represented a reasonable implementation of the Settlement Agreement and were not unduly preferential to SCE’s affiliates. The Standard Transition PPA applicable to baseload operating CHP facilities contain standard pricing, as well as standard terms and conditions, for which Sycamore and KRCC were entitled but there are no standard pricing or standard terms and conditions applicable to the dispatchable generating units under the Settlement Agreement. The parties disagreed sharply on the standard under the CHP Settlement applicable to dispatchable capacity under agreements covering the Transition Period under the Settlement Agreement. KRCC/Sycamore asserted that the relevant market for “competitive market prices” referenced in the Settlement Agreement was limited to CHP 85

Based on discussions with SCE personnel, the reason that SCE did not publicly state its policy regarding contract modifications was out of concern that to do so might encourage counterparties to request more modifications, including more substantial ones.

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facilities with dispatchable generation. SCE contended that it applied to generation in the California market more broadly. The parties ultimately agreed to a combined capacity price between the RA Confirmation and the UC Toll Confirmation of $51.96/kW-year. With regard to pricing for the dispatchable capacity, the IE’s opinion is that the reasonableness of the pricing is dependent on one’s interpretation of the Settlement Agreement and the applicability of evidence provided by SCE in support of the contract pricing. In its oversight role, the IE was required to focus on the Settlement Agreement itself, the conduct of the negotiations, and the evidence of extrinsic pricing in assessing whether SCE treated its affiliates on a non-preferential basis. SCE, on the one hand, and KRCC and Sycamore, on the other hand, negotiated contractual terms and conditions and modifications to the pro forma Dispatchable Agreements for the dispatchable units primarily in relation to the Sycamore RFO Agreements, which had been negotiated in the context of SCE’s first CHP RFO. Since this IE monitored the negotiation of the Sycamore RFO Agreements and found them to be negotiated on a non-preferential basis in a previous report, the IE’s monitoring of the Sycamore and KRCC Transition Agreements focused on modifications to terms and conditions from the Sycamore RFO Agreements as well as on modifications to the Standard Transition PPA. The IE found those modifications to be reasonable and not the result of preferential treatment to an affiliate. Specifically, with regard to the negotiated price for dispatchable capacity under the Transition Dispatchable Agreements, the IE’s conclusions can be summarized as follows: 

 

If “competitive market price” is interpreted as meaning the general CAISO market place and is not limited to CHP dispatchable facilities only: o The $51.96/kW-year contract price has not been supported by benchmark evidence regarding market prices for similar transactions; o The $51.96/kW-year contract price can be justified if CAISO’s $67.50 Capacity Pricing Mechanism pricing for backstop capacity or SCE’s 2012 RA contract with the Sutter project are the relevant “benchmarks” based on a showing that there is a serious likelihood that the KRCC and Sycamore projects may shut down unless non-market pricing is available and there is a reliability need for the generating units; however, factual support for the likelihood of shut down or the reliability need for the generating units has not been provided; If “competitive market price” is limited to CHP dispatchable facilities only, the $51.96/kW-year contract price is supported by extrapolating from benchmark evidence; If the Settlement Agreement is so ambiguous so that neither interpretation can be embraced, the $51.96/kW-year contract price could be supported in light of the savings to ratepayers flowing from the Transition Agreements relative to continuation of the higherpriced Legacy PPAs (based on the possibility that the Legacy PPAs would continue to have been extended by the Energy Division).

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These matters were of particular difficulty for the IE and the parties in light of the issues of first impression as well as the lack of non-affiliated generators who could qualify for “competitive market pricing” for Additional Dispatchable Capacity under a Transition Agreement with SCE, hence, making a comparison to “similarly situated” generators impossible.

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PUBLIC APPENDIX EXTENSION LETTERS

Kern River Cogeneration Company

Box 80478, Bakersfield, CA 93380

(661) 615-4630

--------------------------------Neil E. Burgess, Executive Director

May 18, 2012 KR-10399 SY-10161 Edward Randolph Director Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102

Re:

Renewed Request for Extension Pursuant to the OF/CHP Settlement Section 11.2.1

Director Randolph, By correspondence dated March 20, 2012 you granted, for good cause shown, a requested extension of the existing Kern River Cogeneration Company (KRCC) and Sycamore Cogeneration Company (Sycamore) extension agreements with Southern California Edison Company (SCE). The requested extension was consistent with Section 11.2.1 of the OF/CHP Program Settlement (Settlement) and Commission Decision 07-09-040. The March 20 correspondence granted, "an extension of time to execute Subsequent PPAs with OFs on extended PPAs ... with SCE until June 1, 2012; [and stated] furthermore, these OFs and SCE shall seek to execute a Subsequent PPA by May 25, 2012." The March 20 correspondence also noted, "OFs continue to have a right to request an additional extension beyond any set deadline." This letter seeks an additional extension for good cause shown pursuant to Section 11.2.1 of the Settlement. Before and after the March 20 extension KRCC and Sycamore have worked diligently to establish Subsequent Power Purchase Agreements with SCE. These efforts have included numerous negotiation sessions related to both the possible RFO PPA and a modified form of the PPA to address the dispatchable and multi-product features of a partial or transitioning CHP to a Utility Prescheduled Facility (UPF). In addition KRCC and Sycamore have drafted and offered proposed terms, conditions and pricing applicable to a CHP/UPF operation. KRCC and Sycamore also have actively

Edward Randolph May 18,2012 Page 2 of 4

participated and are participating in the Pacific Gas & Electric Company (PG&E) RFO as well as the SCE CHP RFO in efforts to secure a Subsequent PPA. Notwithstanding these efforts, there is no applicable Subsequent PPA available to either Sycamore or KRCC at this time from SCE or any utility purchaser pursuant to the Settlement. Accordingly, an extension pursuant to Settlement Section 11.2.1 is necessary. KRCC and Sycamore are both facilities that are transitioning from CHP to UPF status due to the modified needs of their thermal host. While similar in some respects, each has a different status both in terms of their respective transition, and in terms of options currently available relative to a Subsequent PPA. The status of each project is outlined below. Subsequent PPA and Operational Status for KRCC KRCC does have some prospect of securing a Subsequent PPA, but apparently not with SCE. KRCC has been selected for the RFO short list by PG&E and is actively working through the current RFO process. However there will be no Subsequent PPA pursuant to this process until and unless KRCC is successful in the PG&E RFO. Until such time as a Subsequent PPA is available either from PG&E or from some Commission sponsored process, an extension under Section 11.2.1 is necessary. KRCC's existing PPA provides for a form of combined CHP/UPF operation. Over the last five years KRCC has been operating as a OF but with units serving both CHP and UPF style operations (2 units base load and 2 units peaking services). As time has gone by the CHP units' thermal host's need for the base load operation is declining. Accordingly KRCC requires the flexibility (contemplated by the Settlement) to transition to a full UPF (peaking) operation, while continuing to provide multiple power products (base load and dispatchable power). Moreover an applicable contract must provide reasonable commercial terms associated with a CHP to CHP "market" comparison. To date there has been not been an appropriate price for the relevant CHP market or applicable terms to provide for a Subsequent PPA for KRCC from SCE. Subsequent PPA and Operational Status for Sycamore Sycamore's contract situation is comparatively worse than KRCC's. Sycamore has not received any price or contract terms to successfully address its needs as a CHP transitioning to UPF status from SCE. Moreover, Sycamore has been unsuccessful in its efforts with the PG&E RFO. Accordingly, until and unless Sycamore is successful in the SCE RFO process there is no applicable Subsequent PPA for Sycamore available.

Edward Randolph May 18, 2012 Page 3 of 4

From an operational perspective Sycamore faces a significant disadvantage regarding the current failure to implement the Settlement pertaining to UPF resources. Sycamore's existing extension agreement is for a full base load operation (all four units at base load). Sycamore's steam host's thermal demands are declining and over time Sycamore must transition to a UPF (peaker) operation at least for some portion of its four units. This transition should be orderly and reasonably compensatory, but the current SCE positions will not support this transition. Unavailability of Bilateral UPF Subsequent PPAs It has become evident that SCE will likely only offer a Subsequent PPA to affiliates like KRCC and Sycamore through the RFO process, and not through a bilateral negotiation. KRCC and Sycamore are mindful of the following observation in your March 20, 2012 correspondence. "SCE seems to imply... that the only Subsequent PPA options for these facilities are "pro forma PPAs" approved by the Settlement. .. , [and that] existing QFs may seek to negotiate and execute a bilateral contract or modified pro forma contract with SCE that addresses such things as multi-product operations." It appears that as far as SCE is concerned, affiliates like KRCC and Sycamore are not to be accorded this bilateral option, notwithstanding your observation. A UPF is in a unique position to offer multiple products beyond base load capacity, associated energy and associated Resource Adequacy such as peaking services and dispatchable, flexible capacity and associated energy. Supposedly this is a product desirable to the state in light of the need to integrate intermittent resources. But the current CHP UPF efforts seemingly belie this need, at least at this point in time. The pro forma Transition PPA in the Settlement is inapplicable to a multiple power product, combined base load and dispatchable resource like those available from KRCC and Sycamore. Pursuant to the Settlement parties are duty bound to negotiate in good faith to establish agreeable and acceptable conditions for a Subsequent PPA. To date the parties have not achieved this objective.

KRCC and Sycamore have put forth considerable good-faith effort towards a Subsequent PPA by the May 25th deadline set in your the March 20th correspondence. KRCC and Sycamore personnel have devoted countless hours of time and effort addressing multiple agreements required for the Subsequent PPA, including necessary modifications to the pro forma PPA, proposed and re-proposed base load and peaking capacity conditions, and an extensive review and comment on the Large Generator

Edward Randolph May18,2012 Page 4 of 4

Interconnection Agreement (LGIA). This effort has been conducted with a significant overlap in agreement negotiation tasks, competing of terms, deadlines, and even changes in personnel for the SCE negotiating teams. Despite these good-faith efforts there is no reasonable prospect of a Subsequent PPA from SCE or PG&E in time to the May 25th deadline. As a result, and pursuant to Section 11.2.1 of the Settlement Agreement, KRCC and Sycamore seek your written approval to extend the respective Extension Agreements for each company. KRCC and Sycamore are mindful of your acknowledgement that extensions should be granted on a limited and definite time period. However, in this instance that limited period is likely at least until the end of the first solicitation period from SCE and/or PG&E. As an accommodation KRCC and Sycamore seek an extension of 180 days to try to successfully address PPA terms and conditions, finalization of their LGIA and to negotiate a combined base load and peaker PPA, in short, to complete the available process to secure a Subsequent PPA.

Sincerely,

. / #L M~···L/ Neil E. Burgess Executive Director Kern River Cogeneration Company Sycamore Cogeneration Company

Marc Ulrich Vice President, Renewable and Alternative Power [email protected]

September 25, 2012

VIA EMAIL & UPS Edward Randolph Director, Energy Division 505 Van Ness Avenue San Francisco, CA 94102 Re:

Southern California Edison Company's (“SCE’s”) Statement of Position Regarding Anticipated Requests for Additional Extensions by Kern River Cogeneration Company (“KRCC”)/Sycamore Cogeneration Company (“Sycamore”) Pursuant to the Qualifying Facility/Combined Heat and Power (“QF/CHP”) Program Settlement (“Settlement”)

Dear Director Randolph: This letter is submitted in anticipation of additional requests by KRCC and Sycamore, SCE’s affiliates,1 to again extend the terms of their expiring Legacy Combined Heat and Power (“CHP”) Power Purchase Agreements (“PPAs” or “Legacy PPAs”). For the reasons discussed in detail below, SCE requests that upon receipt of such a request, you expeditiously: (1) deny those requests on the grounds that they are without good cause, “unreasonably repetitive,” and “designed primarily to delay termination of the extension of the Legacy CHP PPA”2 and (2) determine that if KRCC and Sycamore want to avoid the termination of their Legacy PPAs, they have to either execute standard Transition PPAs or finalize and execute other Subsequent PPAs on or before September 30, 2012. As you may recall, in Decision (“D.”) 07-09-040, the California Public Utilities Commission (“CPUC”) required SCE and other investor-owned utilities to extend the terms of expiring Legacy PPAs until such time as a new standard contract became available. New contracts became available on November 23, 2011 (“Settlement Effective Date” or “SED”) pursuant to D. 10-12-035, which adopted the Settlement. The Settlement required SCE and the QFs to “use all reasonable efforts” “to transition from [the Legacy PPAs] to an approved and effective Subsequent PPA” on or before March 22, 2012.3 KRCC and Sycamore, however, have systematically sought and obtained extensions to allow them to continue to sell power to SCE under the more favorable terms of their Legacy PPAs for the last six months since the Settlement’s March 22, 2012 deadline for the termination of their Legacy PPAs. Specifically, because KRCC and Sycamore experience less stringent performance requirements and receive more lucrative payments under their Legacy PPAs than they would

1 2 3

SCE, KRCC and Sycamore are subsidiaries of Edison International. See CHP Program Settlement Agreement Term Sheet (“Settlement”) § 11.2.1. Id.

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Edward Randolph Page 2 September 25, 2012 receive under the Transition PPAs, KRCC and Sycamore have refused to enter into a Transition PPA for standard products, unlike all other QFs with Legacy PPAs. Even if KRCC and Sycamore are denied further extensions and execute a contract with an October 1, 2012 effective date, the new contracts would require CPUC and Federal Energy Regulatory Commission approvals which would likely take in excess of six months. The contract therefore will not be implemented before these approvals. Each month of delay not only further compresses the transition period, but also causes SCE’s customers to incur unnecessary and excessive additional costs than they would otherwise experience under a Transition PPA. Accordingly, SCE respectfully requests that no further extensions of KRCC’s and Sycamore’s Legacy PPAs be granted. I.

Settlement Framework, Pertinent Provisions, and Factual Background

The Settlement requires that the “Parties shall use all reasonable efforts to meet conditions that would permit transition from the extensions [Legacy PPAs] to an approved and effective Subsequent PPA within one hundred and twenty (120) days after the Settlement Effective Date. Absent good cause shown, the extension of the Legacy CHP PPA shall terminate and the term of the Subsequent PPA commence no later than one hundred and twenty (120) days after the Settlement Effective Date.”4 The 120 days expired on March 22, 2012. To the extent the Transition PPA does not fit the operations of a particular facility, the Settlement specifically provides an amendment procedure for modifying the executed Transition PPA to accommodate the “few CHP facilities” like KRCC and Sycamore.5 The Settlement states that, “In addition to these standard products, a Seller may elect to sell to Buyer under a Transition PPA Additional Dispatchable Capacity (“ADC”) above the standard contract capacity set forth in the Transition PPA (Additional Dispatchable Capacity). Buyer must negotiate in good faith for 120 days to amend the Transition PPA to incorporate a competitive market price for the [ADC]. If negotiations are unsuccessful, Buyer and Seller will mediate the terms of the amendment using the mediation procedures set forth in Section 10.02 of the Transition PPA.”6 This procedure is the same regardless of whether the dispatchable capacity is referred to as ADC or is from a Utility Prescheduled Facility (“UPF”). Not surprisingly, for the reason identified above, these negotiations have been ongoing but unsuccessful and have recently ceased.7 Indeed, most recently, the parties participated in a mediation on September 12, 2012 with Administrative Law Judge Semcer, but were unsuccessful in reaching an agreement. The conclusion of the mediation effectively ended all negotiations for Subsequent PPAs.

4 5 6 7

Settlement § 11.2.1 (emphasis added.) Settlement § 3.4.1.2 Settlement § 11.2.1 SCE can provide a Chronology of Events to the CPUC if needed.

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Edward Randolph Page 3 September 25, 2012 An IOU’s decision not to buy ADC, even if the seller is a UPF, does not warrant extension of a Legacy PPA. The Settlement expressly grants the Buyer the right to accept or reject the offer to purchase ADC, and provides an alternative path for sale for the Seller should the Buyer reject the ADC offer. “If the Buyer elects not to accept Seller’s offer of Additional Dispatchable Capacity for the term of the Transition PPA, then the Buyer, as the Scheduling Coordinator, will facilitate an alternative sale and delivery of the Dispatchable Capacity to the CAISO market, so long as such capacity meets the CAISO determined requirements for compliance with the CAISO Tariff and Protocols.”8 In sum, rather than providing for repeated extensions of the Legacy PPAs on the eve of their expiration date, the Settlement instead requires the parties to enter into a standard Transition PPA for standard energy and capacity products and to thereafter endeavor to come to terms on ADC or UPF. Purchases of ADC, even from a UPF, are not mandatory. It is within the Buyer’s sole discretion to determine if the offer is a competitive market price.9 Further extensions will only serve to continue this pattern indefinitely, causing SCE’s customers to unnecessarily continue to incur higher costs.

II.

No Good Cause Exists for Another Extension of KRCC’s and Sycamore’s Legacy PPAs

As the Energy Division already acknowledged in its March 20, 2012 letter, KRCC and Sycamore are not entitled to unlimited extensions until they execute bilateral contracts with SCE. To the contrary, the Settlement contemplates that the IOU and the seller will first enter into a standard Transition PPA and then negotiate an amendment to accommodate either the Buyer’s purchase of ADC at a competitive market price or the Buyer’s facilitation of ADC to market. To date, KRCC and Sycamore have neither executed a Transition PPA nor offered a competitive market price for their ADC. As such, the parties have not been able to reach agreement. This is not because SCE or its CHP RFO created any constraints on such negotiations.10 SCE’s good faith negotiations with KRCC and Sycamore predate the Settlement and have been ongoing. There has never been any constraint on SCE’s ability to negotiate terms of a Subsequent PPA with KRCC and Sycamore. Additionally, it is not the case that being a UPF is any impediment whatsoever to KRCC and Sycamore’s execution of a Transition PPA. The Settlement procedure set forth above for executing a Transition PPA and thereafter negotiating a price for ADC precisely applies to

8 9

10

Id. As discussed below, this procedure set forth in Section 3.4.1.2 of the Settlement precisely applies to KRCC’s situation irrespective of whether or not it is a UPF. You should not countenance any argument by Sycamore that it is a UPF because it does not operate as a dispatchable facility. As a result of the CHP RFO, the parties have negotiated agreements that could serve as a template for a Subsequent PPA.

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Edward Randolph Page 4 September 25, 2012 KRCC’s situation irrespective of whether or not it is a UPF. With respect to ADC, SCE is only required to entertain offers at competitive market prices and may reject those that are not competitive and opt to instead facilitate KRCC’s sale of ADC to the CAISO market. Accordingly, if KRC and Sycamore raises specious UPF-related arguments, they should be rejected as dilatory. In sum, the fact that KRCC and Sycamore refuse to accept that SCE does not find their offers competitive or to acknowledge the Settlement’s alternative process of facilitating sales and delivery to the CAISO market as a mechanism to handle ADC does not warrant further extension of their Legacy PPAs to the detriment of SCE’s customers. KRCC and Sycamore have had more than ample time to negotiate a Subsequent PPA that covers all products. No further delay of the termination of the Legacy PPA is appropriate. In addition, the parties’ respective positions have been well known since before the September 12 mediation. Nonetheless, although SCE is certain KRCC and Sycamore intend to seek an extension, to date, KRCC and Sycamore have yet to utilize the mandated written extension request procedure set forth in the Settlement. Their delay can only serve to further prolong their ability to continue receiving payments under the more lucrative Legacy PPAs. Accordingly, the Energy Division should take immediate action to remind KRCC and Sycamore of their options to either (1) execute standard Transition PPAs or (2) finalize and execute Subsequent PPAs that cover all products on or before September 30. Respectfully submitted,

Marc L. Ulrich, Ph.D.

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Michael Alcantar [email protected]

September 27, 2012 KR-10399 SY-10161 Edward Randolph Director Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 Re: Good Cause Extension Pursuant to the QF/CHP Settlement Section 11.2.1 Director Randolph, Kern River Cogeneration Company (KRCC) and Sycamore Cogeneration Company (Sycamore) have engaged recently in discussions with your staff and other Commission representatives regarding the progress in framing a transition power purchase agreement with Southern California Edison Company (SCE). Pursuant to those discussions, and staff’s recommendation, KRCC and Sycamore seek a brief, good cause extension pursuant to Section 11.2.1 of the QF/CHP Program Settlement. On June 8, 2012 you granted an extension of the existing Legacy CHP PPAs of KRCC and Sycamore until October 1, 2012, and a further extension if each of the facilities executes a Transition PPA or other Subsequent PPA pending regulatory approval by this Commission and/or by FERC. In good faith the parties have engaged regularly and actively in negotiations regarding the establishment of terms and conditions as well as appropriate pricing consistent with the Settlement. To the parties’ credit there is agreement on a major and material issue demonstrating progress in the development of a Transition or Subsequent PPA. SCE has agreed to utilize the terms and conditions from the recent, successful Sycamore bid to the SCE CHP/Utility Prescheduled Facility (UPF) only RFO. This removes a significant issue related to the necessary accommodation of a UPF facility under the Transition PPA as outlined in your June 8th correspondence. This leaves a single, but critical, remaining issue – the appropriate transition price under the Settlement for UPF resource like KRCC and Sycamore.

The June 8th correspondence indicated a basis for establishing this price pursuant to the Settlement obligations and the related CPUC decisions approving the Settlement -- “As of May 31, and certainly after July 2, 2012, SCE should have knowledge, based on its RFO, about competitive market prices for CHP facilities operating as UPFs.” The parties now have this information. Good cause exists for a brief extension from October 1, 2012 until October 20, 2012 for several reasons. The parties require the guidance of the Commission regarding the proper pricing standards under the Settlement to resolve the remaining issue for the Transition PPAs for both KRCC and Sycamore. The Energy Division staff needs

Edward Randolph, Director CPUC Energy Division August 25, 2009 Page 2

additional time to assist the parties in this regard. The parties have, in good faith, actively engaged in negotiations to secure a resolution. The parties have engaged in a jointly supported mediation to identify and narrow issues in dispute. The remaining issue is subject to the Commission’s direction and prior decisions warrant the engagement of parties and Commission staff for resolution short order. For all of these reasons good cause exists to grant a brief extension. KRCC and Sycamore look forward to working actively with the Energy Division to bring this matter regarding the Transition PPA to a close.

Very truly yours,

Michael Alcantar Counsel to KRCC and Sycamore Cc: Marc Ulrich, SCE, Vice President, Renewable and Alternative Power Nicole Neeman Brady, SCE, Director of Contracts, Renewable and Alternative Power Barry Sheingold, Independent Evaluator Michael Colvin, California Public Utilities Commission Frank Lindh, California Public Utilities Commission Paul Clanon, California Public Utilities Commission Andy Schwartz, California Public Utilities Commission Jason Houck, California Public Utilities Commission Neil Burgess, KRCC and Sycamore Gaylord Edwards, KRCC and Sycamore

Michael Alcantar [email protected]

October 9, 2012 KR-10403 SY-10166 Edward Randolph Director Energy Division California Public Utilities Commission 505 Van Ness Avenue San Francisco, CA 94102 Re

KRCC and Sycamore Emergency Request Pursuant to Section 11.2.1 of the QF/CHP Program Settlement

Dear Director Randolph: This emergency request arises from Southern California Edison Company’s (SCE) unilateral demands and “take-it-or-leave-it” conditions related to the appropriate contract terms for Kern River and Sycamore Cogeneration Companies (KRCC and Sycamore, respectively) under the QF/CHP Program Settlement (Settlement). SCE has demanded a response from KRCC and Sycamore by 3 p.m. today to accept unilateral pricing and revised terms and conditions for a “Transition” PPA. This unilateral contract does not comply with the requirements of the Settlement for either a Subsequent PPA or a Transition PPA. Time is of the essence to seek and secure the Energy Division’s enforcement of a critical provision of the Settlement, specifically Section 11.2.1. The essential issues for your consideration are as follows: 1. Settlement Section 11.2.1 is directly applicable to Sycamore and KRCC because they are facilities under extension agreements ordered by the Commission under Decision 07-09-040. 2. This section provides that “Extensions of the Legacy CHP PPAs ordered by the Commission pursuant to D.07-09-040 shall remain in effect until the date the Seller commences power deliveries under a Subsequent PPA [as distinguished from a Transition PPA] pursuant to the Settlement.” 3. Despite good faith efforts, there was, and there is still, no bilateral or RFO Utility Prescheduled Facility (UPF) immediately available to these facilities. Sycamore has successfully secured an RFO PPA, i.e., a Subsequent PPA, effective in 2014, but there is no currently available bilateral, Subsequent PPA for Sycamore or KRCC.

Edward Randolph October 9, 2012 Page 2

4. The unavailability of a Subsequent PPA is good cause under Section 11.2.1. 5. Settlement Section 4.8.1.1 provides that a Utility Prescheduled Facility is eligible to participate in a CHP RFO or to obtain a PPA through bilateral negotiations or amend an existing Legacy PPA through bilateral negotiations. 6. Bilateral negotiations have not yet resulted in a bilateral agreement regarding an acceptable Subsequent PPA. The Transition PPA is not applicable to a UPF, or required for a UPF, under the Settlement. Section 11.2.1 provides for a “transition” by directing the used of the existing extension agreement until the development of an acceptable Subsequent Agreement, either through and RFO or bilateral negotiations. 7. KRCC and Sycamore relied upon representations from SCE that a possible use of the successful Sycamore RFO bid PPA could serve as a template for an acceptable Subsequent PPA. Unfortunately SCE neither honors the pricing from that RFO PPA, nor the non-price terms and conditions. SCE is proposing at this time material and substantive changes to the RFO PPA terms and conditions. Time limits currently in place -- the current Energy Division extension expires on October 15, and SCE’s unilateral insistence on a take it or leave it deadline by 3 p.m. today – leave KRCC without the protections of Settlement Section 11.2.1, or the time to find acceptable alternatives. KRCC and Sycamore need the engagement and support of the Commission regarding the enforcement of Section 11.2.1. No Settlement party contemplated that transition pricing would be subject to negotiation, yet absent enforcement of Section 11.2.1, this is the current condition for KRCC and Sycamore. By this emergency request KRCC and Sycamore seek an immediate response to grant extensions of the existing KRCC and Sycamore extension agreements pending the establishment of Subsequent PPAs for these facilities under a bilateral negotiation process or pursuant to an RFO process consistent with Sections 4.8.1.1 and 11.2.1. Time is of the essence in this matter. We await your direction and resolution.

Very truly yours,

Michael Alcantar cc:

Commissioner Michel Florio Marc Ulrich, SCE - Vice President, Renewable & Alternative Power Nicole Neeman Brady - Director, Renewable & Alternative Power Contracts Barry Sheingold, Independent Evaluator

Edward Randolph October 9, 2012 Page 3

Frank Lindh, CPUC General Counsel Andrew Schwartz, CPUC - Chief Energy Advisor Jason Houck, CPUC - Energy Policy Analyst, Energy Division Michael Colvin, CPUC - Energy Advisor to Commissioner Mark Ferron

Confidential Appendix D

Appendix E

DECLARATION OF DAHLIA SEIGEL REGARDING THE CONFIDENTIALITY OF CERTAIN DATA

I, Dahlia Siegel declare and state: 1.

I am an energy contracts and trading specialist with Southern California Edison

Company (“SCE”). I was the primary negotiator on behalf of SCE on the executed Combined Heat and Power (“CHP”) Power Purchase and Sale Agreements between SCE and KRCC and Sycamore. As such, I have reviewed SCE Advice 2825-E (“Advice Letter”). I make this declaration in accordance with California Public Utilities Commission (“CPUC”) Decision (“D.”) 06-06-066 and D.08-04-023, issued in Rulemaking 05-06-040. I have personal knowledge of the facts and representations herein and, if called upon to testify, could and would do so, except for those facts expressly stated to be based upon information and belief, and as to those matters, I believe them to be true. 2.

Listed below are the data in this advice letter for which SCE is seeking confidential

protection and the categories of the Matrix of Allowed Confidential Treatment Investor Owned Utility Data (“Matrix”) appended to D.06-06-066 to which these data correspond.

Pages Final Independent Evaluator Report Confidential Appendix 3.

Matrix Category

VIII. B Specific quantitative analysis involved in Confidential scoring and evaluation Appendix D of participating bids

Limitations on Confidentiality Specified in Matrix Evaluation guidelines should be public. Other information confidential for three years after winning bidders selected.

SCE is complying with the limitations on confidentiality specified in the Matrix

that pertain to the data listed in the table in paragraph 2.

4.

I am informed and believe and thereon allege that the data in the table in paragraph

2 above cannot be aggregated, redacted, summarized, masked or otherwise protected in a manner that would allow partial disclosure of the data while still protecting confidential information. 5.

I am informed and believe and thereon allege that the data in the table in paragraph

2 above has never been made publicly available. I declare under penalty of perjury under the laws of the State of California that the foregoing is true and correct. Executed on December 13, 2012 at Rosemead, California.

____________________________________ Dahlia Siegel