LAW-#1779333-v1-A0804011 PFM for CPV Amendment Public...As the result of a ruling in a lawsuit filed against the South Coast Air Quality Management District (“SCAQMD”), however,

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE

STATE OF CALIFORNIA

In the Matter of the Application of SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) for Approval of Results of Standard Track of Its New Generation Request for Offers and for Cost Recovery.

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Application No. 08-04-011 (Filed April 4, 2008)

PETITION OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) FOR MODIFICATION OF DECISION 08-09-041

PUBLIC VERSION

MICHAEL D. MONTOYA MELISSA HOVSEPIAN

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-6054 Facsimile: (626) 302-3990 E-mail: [email protected]

Dated: December 10, 2010

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STATE OF CALIFORNIA


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PETITION OF SOUTHERN CALIFORNIA EDISON COMPANY (U 338-E) FOR MODIFICATION OF DECISION 08-09-041

Pursuant to Rule 16.4 of the Rules of Practice and Procedure of the California Public

Utilities Commission (the “Commission”) and Public Utilities Code Section 1708, Southern

California Edison Company (“SCE”) respectfully submits this petition for modification

(“Petition”) of Decision (“D.”) 08-09-041, entitled “Decision Approving Application of Southern

California Edison Company For Authorization To Accept Results Of the Standard Track Request

For Offers For New Generation And For Cost Recovery” (the “Standard Track Decision”).

Among other things, the Standard Track Decision approved a contract between CPV Sentinel,

LLC (“CPV”)1 and SCE (the “CPV Sentinel II Contract”) on September 18, 2008. In a separate

proceeding (Application 07-02-026), the Commission issued another decision D.08-04-011

entitled “Opinion Granting Application Of Southern California Edison Company For Approval

Of Contract With CPV Ocotillo, LLC” (the “Fast Track Decision”), which approved another

contract between CPV and SCE (the “CPV Sentinel I Contract”) on April 10, 2008. This

Petition requests that the Commission modify the Standard Track Decision to approve SCE’s

amended and restated contract with CPV (the “Amended CPV Contract”), which is an

amendment and restatement of the two existing CPV contracts (collectively, the “CPV

1 The Fast Track Decision approved a contract with CPV Ocotillo, LLC, which has since been renamed CPV Sentinel, LLC. CPV Sentinel, LLC is a special purpose entity and joint venture between GEL Funding, Inc. and CPV Power Development, Inc.

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Contracts”) into a single contract. SCE has concurrently filed a petition for modification of the

Fast Track Decision pertaining to the CPV Sentinel I Contract to approve the Amended CPV

Contract. As discussed in more detail below, the Commission should approve the Amended

CPV Contract because it remains a beneficial contract to all benefiting customers.

I.

INTRODUCTION

In the Fast Track Decision, the Commission approved SCE’s application for

authorization to sign the CPV Sentinel I Contract that was selected from SCE’s fast-track request

for offers (“Fast Track RFOs”) for new generation that could be on-line by August 1, 2010.2 The

CPV Sentinel I Contract is a 10-year contract with CPV for up to 455 megawatts (“MW”) of

capacity and energy from five General Electric LMS 100 combustion turbine generators to be

located in Riverside County, California (the “CPV Facility”). In the Standard Track Decision,

the Commission approved SCE’s application for authorization to sign four power purchase

agreements for up to 1,350.3 MW of capacity that SCE selected as part of its Standard Track

request for offers (“Standard Track RFOs”) for new generation that could be on-line by

August 1, 2013.3 Among these agreements, the Commission approved the CPV Sentinel II

Contract, which is a 10-year contract with CPV that added up to 273 MW 4 of expected capacity

and energy from three additional General Electric LMS 100 gas turbines to be located at the CPV

Facility. The Fast Track and Standard Track Decisions (collectively, the “New Gen Decisions”)

also approved the allocation of the benefits and costs of the CPV Contracts to all benefiting

customers.5

As the result of a ruling in a lawsuit filed against the South Coast Air Quality

Management District (“SCAQMD”), however, CPV was unable to obtain air permits it needed to

2 See D.08-04-011 at 1. 3 See D.08-09-041 at 1. 4 See id. at 3. 5 See D.08-04-011 at 10; D.08-09-041 at 14.

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complete construction of the CPV Facility under the time-frame contemplated in the CPV

Contracts. Newly-passed legislation, however, made it possible for CPV to obtain the necessary

air permits, and SCE and CPV entered into negotiations to move the project forward. The parties

thereafter agreed to the Amended CPV Contract, which, among other things, adjusts the expected

initial delivery date of the entire CPV Facility to accommodate CPV’s new construction schedule

and provides for a price change for the CPV Sentinel I Contract price to the CPV Sentinel II

Contract (Standard Track) price.6

SCE now files this Petition seeking to modify the Standard Track Decision to approve the

Amended CPV Contract and authorize SCE to allocate the costs and benefits of it to all

benefiting customers. In this Petition, SCE explains why it was necessary to amend the CPV

Contracts and why the Commission should approve the amended contract. SCE also

demonstrates that in addition to providing a net present value (“NPV”) improvement to all

benefiting customers (the Amended CPV Contract has a NPV of | | | | | | | | | | | | | as compared to

the original CPV Contracts’ NPV of | | | | | | | | | | | | |),7 the new contract is also advantageous to all

benefiting customers under the Least-Cost/Best-Fit (“LCBF”) methodology, and received proper

independent review from the cost allocation methodology (“CAM”) Group, the Independent

Evaluator (“IE”), and an independent engineer. Accordingly, the Commission should grant the

Petition and approve the Amended CPV Contract as set forth in the Petition.

II.

BACKGROUND

A. SCE’s RFOs For New Generation

On July 20, 2006, the Commission issued D.06-07-029, which directed SCE to issue a

Request for Offers (“RFO”) seeking up to 1,500 MW of long-term contracts for new generation

6 The Amended CPV Contract is attached hereto as Appendix A. 7 See Declaration of Ranbir Singh (“Decl. Singh”) at ¶ 9, attached hereto as Appendix B.

4

resources (“New Gen RFO”).8 The decision also established a cost allocation mechanism

(“CAM”) designed to fairly allocate costs and benefits to all benefiting customers.9 The decision

designated the investor-owned utilities (“IOUs”) as the procurers of new generation for the

benefit of their entire service territories.

On August 14, 2006, SCE issued an RFO soliciting up to 1,500 MW of power purchase

agreements lasting up to 10 years from new generation facilities. Initially, SCE’s New Gen RFO

solicited two types of proposals: (1) Fast Track projects that could come on-line on or before

August 1, 2010; and (2) Standard Track projects that might need more time to come on-line, but

could be available on or before August 1, 2013. Based on an Assigned Commissioner’s Ruling,

SCE added a third track to its New Gen RFO, the Summer 2007 Track, targeting new generation

facilities that could come on-line on or before August 1, 2007.10 In the Summer 2007 Track and

Fast Track, SCE entered into three power purchase agreements for a total capacity of 1,205 MW.

On December 20, 2007, the Commission issued D.07-12-052, which authorized SCE to procure

1,200 to 1,700 MW of new generation resources by 2015, in addition to the 295 MW11 of

procurement authority remaining in the Standard Track of SCE’s New Gen RFO.12

Pursuant to an application filed by SCE (A. 07-02-026), the Commission approved the

CPV Sentinel I Contract on April 10, 2008 as part of the Fast Track, and authorized SCE to

allocate the costs and benefits of the contract to all benefiting customers in accordance with the

CAM adopted in D.06-07-029 and D.07-09-044.13 In March 2008, as part of the Standard Track,

SCE entered into four power purchase tolling agreements, including the CPV Sentinel II

8 See D.06-07-029 at 47, 62-63 (OP 7). 9 The CAM allocates the benefits and costs of new generation resource procurement to all benefiting customers in

an IOU’s service territory, including bundled service customers, direct access customers, and community choice aggregation customers. See D.06-07-029 at 7, 25-27, 56 (FOF 18-19), 60-61 (COL 5-7) (The term “benefiting customers” is defined in D.06-07-029 at 26 n.21.).

10 See Assigned Commissioner’s Ruling Addressing Electric Reliability Needs in Southern California for Summer 2007, R.06-02-013, at 6 (Aug. 15, 2006).

11 Although D.07-12-052 states that there is 305 MW of the original 1,500 MW of procurement authority authorized in D.06-07-029 remaining in the Standard Track, there is actually 295 MW remaining after the 1,205 MW of power purchase agreements executed by SCE in the Summer 2007 and Fast Tracks.

12 See D.07-12-052 at 278 (FOF 46), 291 (COL 7), 300 (OP 5). 13 See D.08-04-011 at 16, 18.

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Contract, with a total capacity of 1,350.3 MW.14 Pursuant to an application filed by SCE (A.08-

04-011), the Commission approved all four contracts as part of the Standard Track, and

authorized SCE to allocate the costs and benefits of the contracts to all benefiting customers in

accordance with the CAM.15

B. Air Permits For the CPV Facility – Lawsuit and Legislative Fix

After SCE received Commission approval, CPV began taking steps to construct the CPV

Facility. The construction process, however, coincided with a lawsuit brought by the National

Resources Defense Council (“NRDC”) and others against the SCAQMD challenging the validity

of its internal bank of offsets for PM10 emissions known as the Priority Reserve. Then-existing

law required every air pollution control district or air quality management district in a federal

nonattainment area for any national ambient air quality standard pollutant to establish, by

regulation, a system by which all reductions of air contaminant emissions used to offset certain

future emission increases are banked prior to use. The SCAQMD promulgated various rules

establishing offset exemptions, providing priority reserve offsets and creating or tracking credits

used for offset exemption or priority reserve projects. In Natural Resources Defense Council v.

South Coast Air Quality Management District, a Los Angeles Superior Court judge found the

promulgation of certain of these district rules to be in violation of the California Environmental

Quality Act (“CEQA”).16

Following that ruling, the SCAQMD stopped issuing any permits based on Priority

Reserve PM10 emission offsets or exemptions from these offsets. This impacted several of the

projects awarded contracts in the New Gen RFOs including CPV. The freeze prevented these

projects from obtaining the air permits needed to construct facilities.

14 SCE’s application and accompanying testimony in A.08-04-011 provides a complete discussion of SCE’s Standard Track New Gen RFO.

15 See D.08-09-041 at 16, 18. 16 See Natural Resources Defense Council v. South Coast Air Quality Management District (Super. Ct. Los

Angeles County, 2007, No. BS 110972).

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In response to the NRDC decision, the state legislature took action in order to allow

construction of new generation within the SCAQMD. One action applicable only to the CPV

project was Assembly Bill (“AB”) 1318, signed by the Governor in October 2009, which, among

other things, allowed the SCAQMD to transfer a limited number of emission credits from its

Priority Reserve to the CPV project upon receipt of payment from CPV of mitigation fees and

validation of the offsets by the California Energy Commission (“CEC”).17 In other words, AB

1318 permitted the SCAQMD to issue PM10 emission offsets to CPV for new capacity so long

as certain requirements were met. The CEC siting committee recommended approval of the

CPV project on October 5, 2010.

C. Contract Amendment

Upon execution of the CPV Contracts, CPV posted | | | | | | | | | | | | in initial development

security with SCE on the CPV Sentinel I Contract and | | | | | | | | | | | on the CPV Sentinel II

Contract. The CPV Sentinel I Contract required CPV to post additional development security of

| | | | | | | | | | | | upon the acquisition of their construction permit or at least 30 business days prior

to the expected initial delivery date and | | | | | | | | | | | | on the CPV Sentinel II Contract once the

Commission approved the contracts. But, as described above, the freeze on the issuance of any

new air permits by the SCAQMD caused by NRDC’s lawsuit prevented CPV from proceeding

with the construction of the facility. Thus, once the Commission approved the CPV Sentinel II

Contract, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

and beginning on June 21, 2010 (30 business days prior to the initial expected delivery date),

SCE has extended the expected initial delivery date of the CPV Sentinel I Contract.

17 See Health & Safety Code § 40440.14; SCAQMD Resolution No. 10-20 Adopting State Implementation Plan Revision To Implement AB 1318 (July 9, 2010). Subsequent to its passage, the California Communities Against Toxics and others challenged AB 1318 in Los Angeles Superior Court. See California Communities Against Toxics et al. v. State of California et al., (Super. Ct. Los Angeles County, 2009, No. BS 124264). The Court granted a judgment on the pleadings for the State and dismissed the challenge.

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The delays in obtaining permits, however, made it impossible to complete construction of

the CPV Facility by the original expected initial delivery date of August 1, 2010 for the CPV

Sentinel I Contract and May 1, 2012 for the CPV Sentinel II Contract. After AB 1318 was

signed into law in October 2009, CPV approached SCE with a proposed amendment to the CPV

Contracts that would allow the project to move forward. SCE rejected the proposal but,

consistent with other new generation contracts impacted by the NRDC decision, SCE continued

to negotiate with CPV. Ultimately, the parties agreed to an August 1, 2013 initial delivery date

for both contracts and a potential extension to May 1, 2014 (if final Commission approval and

permits are not obtained and certain legal actions have not been resolved in CPV’s favor by June

30, 2011), a price change for the CPV Sentinel I Contract to the CPV Sentinel II Contract

(Standard Track) price, application of the CPV Sentinel II Contract’s Delivery Date Security to

all 8 units, and the changes described in Section V below. SCE executed the Amended CPV

Contract on November 30, 2010.

Fundamentally, there is little change between the original contracts and amended

agreement. Under the Amended CPV Contract, SCE, and all benefiting customers, still receive

up to a total of 728 MW of expected contract capacity and associated energy from the CPV

Facility to be constructed in Riverside, California, which will consist of eight LMS 100 units

(collectively, the “Units” or individually the “Unit”) featuring combustion turbines in simple

cycle configuration and fueled by natural gas only. The CPV Facility is still located in an area

where it can support grid stability, renewable integration, and voltage support for the Los

Angeles Basin. The expected initial delivery date for the CPV Facility, however, changes to

August 1, 2013 (with a potential extension to May 1, 2014) for a term of ten years.

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III.

SCE COULD NOT HAVE FILED THIS PETITION WITHIN ONE-YEAR OF THE NEW

GEN DECISIONS’ EFFECTIVE DATES

Rule 16.4(d) of the Rules of Practice and Procedure of the Commission provides that, if a

petitioner files a petition for modification beyond one year of the effective date of the decision it

seeks to modify, the petitioner must justify why it could not have filed the petition earlier. In the

present case, the New Gen Decisions’ effective dates are April 10, 2008 and September 18, 2008

and the one-year periods would have expired on April 10, 2009 and September 18, 2009

respectively. SCE, however, has justification for the filing this Petition beyond the one-year

period.

SCE and CPV did not execute the Amended CPV Contract until recently, November 30,

2010. Therefore, until that date, there were simply no amended contracts that required

Commission approval under the New Gen Decisions.

Moreover, CPV’s difficulty in obtaining air permits, which necessitated amending the

CPV Contracts, was the result of a series of events that were beyond SCE and CPV’s control. As

described above, in July 2008, a Los Angeles Superior Court judge found the SCAQMD’s

promulgation of certain air permit rules violated CEQA.18 Following that ruling, the SCAQMD

stopped issuing the type of permits that would allow CPV to construct the CPV Facility. It was

not until October 11, 2009 that Governor Schwarzenegger signed AB 1318 into law, which,

among other things, allowed CPV to obtain the requisite air permits. Shortly thereafter, CPV

approached SCE with the idea of amending the CPV Contracts in order to modify the expected

delivery dates. These events occurred approximately one year after the issuance of the New Gen

Decisions. Because these events, which were beyond SCE and CPV’s control, made it

18 See Natural Resources Defense Council v. South Coast Air Quality Management District (Super. Ct. Los Angeles County, 2007, No. BS 110972).

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impossible for the parties to execute the Amended CPV Contract before the Rule 16.4(d) one-

year deadline, it is reasonable for the Commission to accept SCE’s filing of this Petition.

IV.

DESCRIPTION OF CHANGES IN CONTRACT TERMS AND CONDITIONS

On November 30, 2010, SCE and CPV executed the Amended CPV Contract. The two

major changes to the CPV Contract were contract price and the adjustment to the initial delivery

dates. In addition to these major changes, SCE and CPV also agreed to other changes to the

CPV Contracts. SCE provides a chart summarizing these changes, along with a comparison

against the corresponding term from the CPV Contracts, below. Finally, SCE and CPV updated

the agreements in light of the California Independent System Operator (“CAISO”) market

redesign and technology upgrade, and made other changes that are not identified in the table

below.19

Contract Term CPV Sentinel I Contract CPV Sentinel II

Contract Amended CPV Contract

Initial Delivery Date August 1, 2010 May 1, 2012 August 1, 2013 and potential extension to May 1, 2014 (if final Commission approval and permits are not obtained and certain legal actions have not been resolved in CPV’s favor by June 30, 2011)20

| | | | | | | | | | | | | | | | | | | | | | | | | |

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19 A redline of the CPV Contracts against the Amended CPV Contract is attached hereto as Appendix C. 20 See Amended CPV Contract at Section 2.03. 21 | | | | | | | | | | | | | | | | | | | 22 | | | | | | | | | | | | | | | | | |

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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

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Gas Changes Amended CPV Contract has various changes related to the delivery of natural gas to reflect recent SoCal Gas Tariff changes27

MRTU Amended CPV Contract has various changes incorporating the Market Redesign & Technology Upgrade and CAISO Tariff changes28

CAISO Certification Amended CPV Contract requires Seller to obtain CAISO Certification for the Generating Units at least one (1) week prior to the Initial Delivery Date29

GHG language Amended CPV Contract has various changes incorporating more current greenhouse gas language30

NERC Reliability Standards Amended CPV Contract has various changes incorporating current NERC Standards Compliance Penalties language31

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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 32

23 | | | | | | | | | | | | | | | | | | | | 24 | | | | | | | | | | | | | | | | | | | | | 25 | | | | | | | | | | | | | | | | | | | | 26 | | | | | | | | | | | | | | | | | | | | | | | 27 See id. at Section 10.04.03 & Article 16. 28 See id. at Appendix A. 29 See id. at Section 2.04.12. 30 See id. at Section 15.04. 31 See id. at Section 28.06. 32 | | | | | | | | | | | | | | | | | | | | |

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V.

THE AMENDED CPV CONTRACT STILL RESULTS IN AN AGREEMENT THAT IS

BENEFICIAL TO ALL OF SCE’S CUSTOMERS

Similar to the process SCE used to evaluate the contracts in the New Gen Decisions, and

in accordance with D.04-12-048, SCE used a LCBF methodology to value the Amended CPV

Contract. The LCBF methodology is comprised of two processes. SCE uses the first process,

valuation, to value a contract, and addresses the least-cost portion of the methodology. SCE uses

the second process, selection, to decide whether the contract continues to meet all the constraints

and preferences required to meet system needs, and addresses the best-fit portion of the

methodology.

The LCBF process used for the Amended CPV Contract is nearly identical to the analysis

performed on the CPV Contracts.33 Accordingly, as described below, SCE’s evaluation focused

on market valuation based on the modified price and initial start date and an assessment of future

system needs. Based on this evaluation, SCE demonstrates that the Amended CPV Contract is

still a beneficial agreement for all benefiting customers and the Commission should approve the

amendments.

A. Market Valuation – Least-Cost Methodology

SCE used a valuation process for the Amended CPV Contract that was similar to the

process it used in the New Gen RFOs.34 Because the objective of the analysis was to assess the

change in value between the original contracts and the proposed amendment, it was not

necessary to include the value of factors that did not change between the original two contracts

and the single amendment such as transmission upgrade costs.35 Instead, SCE employed a net

33 See Decl. Singh at ¶3. Also, SCE’s application and accompanying testimony in A.08-04-011 provides a complete discussion of SCE’s LCBF process.

34 See id. at ¶4. 35 See id. at ¶5.

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present value (“NPV”) analysis to the Amended CPV Contract.36 This methodology, which is

consistent with SCE’s previous valuations, entails forecasting: (1) the value of capacity, energy

and ancillary services; (2) contract costs; and (3) the net value of (1) and (2).37 SCE does this

analysis under 25 different electric power price scenarios (based on five heat rate scenarios and

five natural gas price scenarios) to ensure it captures valuation under various possible future

market conditions.38 Based on the resulting NPVs and associated probabilities, SCE computed

probability weighted NPVs for both the original and amended CPV contracts.39

SCE performed this analysis using its forecast of the fundamental market prices and

parameters for the Amended CPV Contract and CPV Contracts.40 SCE provides the results of

this valuation in the table below.

CPV Valuation Results41

CPV Contracts Nominal

Capacity Price

($/kWm)

Delivery Start Date Term

Capacity (MW) NPV($MM) NPV($/kWm)

Sentinel I & Sentinel II Contracts

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | |

8/1/2010

5/1/2012 10 years 728 | | | | | | | | | | |

Amended Sentinel Contract | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | |

8/1/2013 10 years 728 | | | | | | | | | | |

Delta | -- -- | | | | | | | |

36 See id. at ¶6. 37 See id. 38 See id. 39 See id. at ¶7. 40 See id. at ¶8. 41 See id. at ¶9.

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The key differences driving the NPV change between the original two CPV Contracts

and the Amended CPV Contract | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |.

The total net NPV improved for the CPV Facility by | | | | | | | | | | | from the original CPV

Contracts to the Amended CPV Contract, and the NPV per kW-month (“kWm”) of | | | | | | for

the amended contract is better than the recently approved El Segundo amendment and other New

Gen contracts signed during the same RFO, as shown in the table below:

Signed Contracts Nominal

Capacity Price

($/kWm)



Amended El Segundo Contract | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | |

8/1/2013 10 years 550 | | | | | | | | | | |

Walnut Creek | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | |

6/1/2013 10 years 479 | | | | | | | | | | |

Wellhead Delano | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

6/1/2012 10 years 49 | | | | | | | | | |

B. Selection Process -- Best-Fit Methodology

In addition to the market valuation discussed above, SCE considered other factors when

evaluating the Amended CPV Contract. SCE reviewed the Amended CPV Contract’s generator

attributes and other qualitative factors to determine whether they fit SP-26 system needs and how

well they met various contractual and regulatory criteria.

14

1. Need for New Generation Resources in SP-26

As noted above, in D.06-07-029 and D.07-12-052, the Commission authorized SCE to

procure up to 3,200 MW of conventional new generation to meet system reliability needs

through 2013. Some key drivers of this system reliability needs at the time of these decisions

were forecast load growth and the potential retirement of aging plants. To date, and including

the capacity represented by the Amended CPV Contract, SCE has procured 2,556 MW. Of the

procured new generation, only 750 MW is on-line. In its decisions approving the original CPV

Contracts (D.08-04-011 and D.08-09-041), the Commission re-affirmed that the CPV project’s

new capacity was needed for system reliability.42 Since the approval of the original CPV

Contracts, the State and the nation have suffered a severe recession, which reversed the trend of

increasing load and actually resulted in a load decrease. Even though the State’s economy has

yet to return to pre-recession growth levels and unemployment remains stubbornly high, there

are signs of economic recovery and SCE’s latest load forecast indicates load growth beginning in

2011. Given uncertainty in the timing and magnitude of the recovery and future load forecasts

generally, coupled with the uncertainty of generator retirements, SCE continues to support the

CPV project as needed for system reliability. Indeed, the uncertainty of generator retirements

has increased since the Commission’s approval of the original CPV Contracts with the adoption

of the California State Water Resources Control Board’s (“SWRCB”) policy on May 4, 2010

concerning the phase-out of once-through cooling (“OTC”) generation.

In SCE’s service territory, there are 9,070 MW of generation that uses OTC technology.

Two units representing 670 MW are required to be in compliance with the new SWRCB’s policy

by December 31, 2015. Another 18 units representing 6,200 MW are required to be in

compliance by December 31, 2020. The San Onofre Nuclear Generating Station, representing

2,200 MW, is required to be in compliance by December 31, 2022. All of this OTC generation is

located in critical areas of the electric grid (7,124 MW are located in the Los Angeles Basin

42 See D.08-04-011 at 16 (FOF 3); D.08-09-041 at 15 (FOF 3).

15

Local Control Area and 1,946 MW are located in the Big Creek/Ventura Local Control Area, as

defined by the CAISO). There is considerable uncertainty at this point as to the extent to which

these plants can comply with the new OTC policy or can justify the cost of compliance. If the

plants cannot comply or economically justify the cost of compliance, they will shut down.

Moreover, the owners of these plants will find it increasingly difficult to justify investing

in their plants if there is a high likelihood of retirement by their OTC compliance dates. SCE is

concerned about degrading system reliability to the extent this on-going investment is reduced.

There is the possibility, for example, that if a costly major repair is needed to a unit several years

before its OTC compliance date, the unit owner will simply retire at that time, rather than

investing money that cannot realistically be recovered from the market before the OTC

compliance deadline.43 The CPV Sentinel units, which are located in the critical Los Angeles

Basin local area, can serve as a replacement for some of this OTC generation that retires on or

before its OTC compliance date. This Los Angeles Basin local area, for air quality management

purposes, is within the jurisdiction of the SCAQMD. Due to the extreme difficulty of obtaining

offsets for emissions (especially for fine particulate matter, such as PM-10) in the SCAQMD

jurisdiction, the ability to replace retiring Los Angeles Basin generation with new generation

within the Los Angeles basin may be severely limited. Accordingly, SCE recommends the

Commission effectively “take advantage” of the SCAQMD offsets the CPV project was able to

obtain through legislation (AB 1318) and approve the Amended CPV Contract which will allow

this Los Angeles Basin plant to be constructed.

Additionally, the CAISO is working with the Commission staff, the CEC, and other

stakeholders to determine what resources the grid will need to provide the appropriate level of

ancillary services and load following capability in the future when higher levels of renewables

will be on-line. This effort may determine that higher levels of new flexible operating resources

43 The SWRCB’s policy requires OTC generators to mitigate their impingement and entrainment impacts five years after the effective date of the policy. It is not clear what mitigation may be required. Obviously, a unit that retires prior to the deadline for interim mitigation will not have to incur mitigation costs.

16

are necessary to operate the grid in a reliable manner. Future system needs may require

modifications or additions to traditional planning reserve margin (“PRM”) criteria, potentially

leading to different types of planning or operational criteria. The locational and operational

characteristics of the CPV Facility support the accomplishment of State policies and appear well-

suited to the system needs of the future.

The CPV Facility, which is comprised of eight quick-start peaking units, has considerable

operating flexibility that will facilitate the integration of renewable generation. The CPV

Facility does not utilize OTC. Moreover, the CPV Facility will use fuel more efficiently than the

aging OTC plants in SCE’s service territory. When originally selecting the CPV Sentinel units,

SCE determined that the addition of these units to the electric grid would reduce overall CO2

emissions.

2. Contractual and Regulatory Criteria

With respect to contractual and regulatory criteria, very little difference between the CPV

Contracts and Amended CPV Contract exists. For example, the Amended CPV Contract does

not alter any of the following attributes that were applicable to the CPV Facility under the CPV

Contracts:

• A project located outside an area deemed an environmental justice area is preferred. The SCAQMD has identified a specific area for environmental justice. The CPV Facility is not located in an environmental justice area.

• Implementation of Section 316(b) of the Clean Water Act may result in additional retirements or operational restrictions of coastal power plants. SCE considers the CPV Facility a preferred resource as it does not rely on OTC technology and would support replacement of OTC units that retire.

• To fulfill SCE’s Renewables Portfolio Standard Program obligations, SCE must consider investments that will facilitate integration of renewable resources. The CPV Facility would support integration of renewable resources as it would provide operational flexibility and grid reliability in the L.A. Basin.

17

VI.

INDEPENDENT THIRD-PARTY REVIEW OF THE AMENDED CPV CONTRACT

A. Engagement Of And Consultation With The Independent Evaluator

In D.04-12-048, the Commission lifted its ban on long-term affiliate transactions for

contracts entered into through an open and transparent solicitation process.44 The decision

mandates the use of an Independent Evaluator (“IE”) in IOU resource solicitations where there

are affiliate, utility-built, or utility turnkey bidders.45 An IE is also required to oversee any

solicitation that produces contracts subject to D.06-07-029’s Cost Allocation Mechanism

(“CAM”).46 As described below, SCE complied with these regulatory mandates by engaging

Sedway Consulting as its IE for the Amended CPV Contract.

The IE participated in all aspects of the Amended CPV Contract, including internal

process meetings, CAM Group meetings, Risk Management Committee meetings, and most

meetings directly with CPV. The IE was part of the process throughout, and had complete

access to any SCE document or meeting relating to the Amended CPV Contract. An additional

description of the IE’s work and results is provided in a separate report on the Amended CPV

Contract prepared by Alan Taylor of Sedway Consulting, Inc.47

B. Consultation With The CAM Group

In D.07-12-052, the Commission ordered the IOUs to consult with a newly created CAM

Group, instead of their Procurement Review Groups (“PRGs”), regarding any procurement for

which an IOU seeks to recover costs from all benefiting customers in accordance with the CAM

established in D.06-07-029.48 The CAM Group is composed of existing PRG members,

44 D.04-12-048 at 128-129. 45 Id. at 135-136. 46 D.06-07-029 at 28. 47 The IE Report is attached hereto as Appendix D. 48 D.07-12-052 at 127-130, 301 (OP 8).

18

Commission Staff, and members representing direct access and community choice aggregator

customers.49

On February 28, 2009, SCE consulted with its CAM Group in connection with its New

Gen RFO regarding selection and valuation. On February 3, 2010, SCE consulted with its CAM

Group regarding amending the CPV Contracts. On November 9, 2010, SCE consulted with its

CAM Group regarding the finalization of the Amended CPV Contract.

C. Independent Valuation of the Amended CPV Contract

On June 6, 2010, SCE retained Black & Veatch to provide independent engineering

services to review and assess the reasonableness of the changes in the Amended CPV Contract,

including those changes related to the construction schedule and pricing. Specifically, Black &

Veatch provided independent verification that the changes in the Amended CPV Contract arise

from changes in the regulatory environment, market conditions for financing, and other

development costs, and are not the result of material increases in profit for CPV or risk shifting

from CPV to all benefiting customers.

In order to complete its review and assessment, Black & Veatch examined, among other

things: (1) permitting documents, the status of submitted applications, and any risk associated

with obtaining permits; (2) the financial model for the CPV Contracts, and a revised financial

model for the Amended CPV Contract, which included CPV’s rate of return under both the

original and amended agreements; and (3) documentation for any price changes for materials and

equipment required for the CPV Facility. Black & Veatch also interviewed appropriate

personnel from both SCE and CPV.

Based on its review, Black & Veatch made several conclusions.50 First, the scope of the

Amended CPV Contract is the same as the original agreements.51 Second, CPV is on track to

49 Id. 50 A copy of Black & Veatch’s Independent Engineering Report is attached hereto as Appendix E (“Independent

Engineering Report”). 51 See Independent Engineering Report at 24-25.

19

obtain or has obtained the appropriate permits, including air permits and CEC-approval of the

project.52 Third, based on Black & Veatch’s review of the project’s financial models, the

Amended CPV Contract’s new capacity price set to the Standard Track price for all 8 units is

“representative of the actual and expected cost changes that have impacted the project.”53 Black

& Veatch further found that the Amended CPV Contract’s price is consistent with other similar

projects and contracts.54 Finally, Black & Veatch determined CPV’s levered, after-tax equity

internal rate of return (“IRR”) as a result of the Amended CPV Contract to be less than that

resulting from the CPV Sentinel I Contract and CPV Sentinel II Contract.55

VII.

MODIFICATIONS TO STANDARD TRACK DECISION

Consistent with Rule 16.4 of the Rules of Practice and Procedure of the Commission,

SCE provides the proposed modifications to D.08-09-041. With respect to the Findings of Fact,

SCE proposes the following additional findings:

• We find that SCE’s conduct in respect of the negotiation of the Amended CPV Contract was reasonable.

• We find that the Amended CPV Contract is needed to preserve system reliability.

• We find that the Amended CPV Contract is reasonable and prudent and that SCE should recover any payments it makes pursuant to the contract in full through rates or such other cost recovery mechanism as may be authorized by the Commission, subject only to SCE’s prudent administration of the contract.

• SCE is authorized to allocate the benefits and costs of the Amended CPV Contract to all benefiting customers in accordance with D.06-07-029.

With respect to Conclusions of Law, SCE proposes the following additional conclusions:

• The Amended CPV Contract for up to 728 MW of expected capacity and associated energy with an expected initial delivery date of August 1, 2013 (and a

52 See id. at 25-26. 53 See id. at 26. 54 See id. at 27. 55 See id. at 19-21.

20

potential extension to May 1, 2014), with the term ending July 31, 2023 (or potentially April 30, 2024), is reasonable and should be approved.

• The costs and benefits of the Amended CPV Contract should be shared with all benefiting customers in SCE’s service territory in accordance with the cost allocation methodology established in D.06-07-029.

With respect to the Ordering Paragraphs, SCE proposes the following additional

paragraphs:

• We authorize SCE to enter into the Amended CPV Contract with CPV Sentinel, LLC for 728 MW of capacity and energy deliverable from August 1, 2013 through July 31, 2023 (or from May 1, 2014 to April 30, 2024, provided that certain conditions are met under Appendix 2.03(B) of the Amended CPV Contract).

• We authorize SCE to allocate the costs and benefits of the Amended CPV Contract to all benefiting customers in accordance with the cost allocation methodology adopted in D.06-07-029.

Respectfully submitted, MICHAEL MONTOYA MELISSA HOVSEPIAN

/s/ Melissa Hovsepian By: Melissa Hovsepian

Attorneys for SOUTHERN CALIFORNIA EDISON COMPANY

2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770 Telephone: (626) 302-6054 Facsimile: (626) 302-3990 E-mail: [email protected]

Dated: December 10, 2010

APPENDIX A CONFIDENTIAL

THIS DOCUMENT CONTAINS CONFIDENTIAL MATERIALS THAT ARE PROTECTED PURSUANT TO CALIFORNIA PUBLIC UTILITIES COMMISSION DECISIONS AND

APPLICABLE LAW. PUBLIC DISCLOSURE IS RESTRICTED.

APPENDIX B CONFIDENTIAL (REDACTED)



1


STATE OF CALIFORNIA


)))) )


DECLARATION OF RANBIR SINGH

I, Ranbir Singh, declare as follows:

1. This declaration is being made in support of the amended Petition of Southern

California Edison Company (“SCE”) for Modification of Decision 08-09-041 (“Standard Track

Petition”).

2. I am the Manager of Portfolio Analysis and Valuation in the Energy Supply and

Management group at SCE. As such, I had responsibility for performing the contract valuation

of the Amended CPV Contract (as defined in the Standard Track Petition).

3. The Least-Cost/Best-Fit (“LCBF”) methodology used for the Amended CPV

Contract is nearly identical to the analysis performed on the CPV Sentinel I and CPV Sentinel II

Contracts (as defined in the Standard Track Petition).

4. SCE used a valuation process for the Amended CPV Contract that was similar to

the process it used in the New Gen RFO (as defined in the Standard Track Petition).

5. The objective of the analysis for the Amended CPV Contract was to assess the

change in value between the original CPV Contracts (as defined in the Standard Track Petition)

and the proposed amendment.

6. SCE employed a net present value (“NPV”) analysis to the Amended CPV

Contract. This methodology, which is consistent with SCE’s previous valuations, entails

2

forecasting: (1) the value of capacity, energy and ancillary services; (2) contract costs; and (3)

the net value of (1) and (2). SCE does this analysis under 25 different electric power price

scenarios (based on five heat rate scenarios and five natural gas price scenarios) to ensure it

captures valuation under various possible future market conditions.

7. SCE computed probability weighted NPVs for the CPV Contracts and Amended

CPV Contract based on the resulting NPVs and associated probabilities resulting from the

analysis described in paragraph 6.

8. For the analysis performed under paragraph 6, SCE used its forecast of the

fundamental market prices and parameters and applied them to the Amended CPV Contract and

CPV Contracts.

9. The CPV Sentinel valuation results are as follows:

CPV Contracts Nominal

Capacity Price ($/kWm)



Sentinel I & Sentinel II Contracts

| | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | |

8/1/2010

5/1/2012 10 years 728 | | | | | | | | | | |

Amended Sentinel Contract | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | |

8/1/2013 10 years 728 | | | | | | | | | | |

Delta | -- -- | | | | | | | |

10. The CPV Contracts and the Amended CPV Contract base variable operations and

maintenance (“VOM”) pricing on the consumer price index (“CPI”). The Amended CPV

Contract is based on a 2013 CPI, and the CPV Sentinel I and Sentinel II Contracts were based on

a 2010 and 2012 CPI respectively. This difference in CPI year and resulting VOM was

negligible in the valuation analysis of the Amended CPV Contract.

3

11. There were no changes in operating characteristics, such as the start-up charges,

Pmin, and start time, and therefore there was no impact on contract valuation.

I declare under penalty of perjury under the laws of the State of California that the

foregoing is true and correct. Executed this 10th day of December, 2010 in Rosemead,

California.

__________/s/ Ranbir Singh__________________

Ranbir Singh

APPENDIX C CONFIDENTIAL



APPENDIX D CONFIDENTIAL (REDACTED)



Sedway Consulting, Inc.

INDEPENDENT EVALUATION REPORT FOR SOUTHERN CALIFORNIA EDISON’S

AMENDMENT TO CPV SENTINEL

POWER PURCHASE AGREEMENT

Submitted by:

Alan S. Taylor Sedway Consulting, Inc.

Boulder, Colorado

December 8, 2010

_________________________ Sedway Consulting, Inc. _________________________

1

Introduction and Background On August 14, 2006, Southern California Edison (SCE) issued a New Generation Request for Offers (New Gen RFO) for power projects to satisfy the utility’s projected incremental resource needs for 2009-2013. The New Gen RFO sought approximately 1,500 MW of new generation to be located in or otherwise electrically interconnected with SP15, the Southern California electricity market area. Ultimately, SCE executed seven power purchase agreements (PPA), two of which were with subsidiaries of Competitive Power Ventures, Inc. (“CPV”) for the development of a new peaking facility near Desert Hot Springs, California. The first CPV PPA was with CPV Ocotillo, LLC and was executed on February 15, 2007. It called for the construction of five General Electric LMS100 combustion turbines with a combined capacity of 455 MW and an expected commercial operation date of August 1, 2010. Although originally called the Ocotillo project, the name of the project was later changed to the Sentinel project. In a subsequent portion of SCE’s solicitation, a second PPA was awarded for an additional three LMS100 CTs at the same site. That PPA was with CPV Sentinel, LLC. It was executed on March 6, 2008 and called for the development of another 273 MW of peaking capacity by May 1, 2012. However, shortly after the execution of the second PPA, CPV’s air permitting efforts were slowed and eventually halted by lawsuits filed against the regional air permitting authority – the South Coast Air Quality Management District (SCAQMD). These lawsuits challenged SCAQMD’s right to issue PM101 emission offsets from a special bank of offsets called the Priority Reserve. The Priority Reserve lawsuits caused a significant delay in the development of the Sentinel project. The path was cleared for CPV’s eventual acquisition of the necessary PM10 offsets with the passage of specific state legislation in late 2009. However, given the permitting delay, it was no longer possible for CPV to develop the Sentinel facility for the prices or schedule embodied in the two PPAs. SCE and CPV commenced negotiations on an amended PPA that, among other things, combined the resources governed by the two PPAs into a single amended PPA and shifted the expected commercial operation date for the entire eight-unit facility to August 1, 2013. That amended PPA is the focus of this Independent Evaluation report. In June, 2006, in compliance with the California Public Utilities Commission’s (CPUC) 2006 long-term procurement order, SCE retained Sedway Consulting, Inc. (Sedway Consulting) to monitor SCE’s resource evaluation and selection process in the New Gen RFO. Sedway Consulting was retained to provide SCE’s Procurement Review Group (PRG, and later, the Cost Allocation Mechanism [CAM]) participants with information and assessments to ensure that the solicitation was conducted fairly and that SCE’s evaluation procedures were appropriately developed and administered. In its continuing role as the independent evaluator (IE) in SCE’s New Gen RFO, Sedway Consulting has continued to monitor developments associated with any and all of the final selected contracts. This Independent Evaluation Report provides an overview of the tasks

1 Particulate Matter - 10 microns


2

undertaken by Sedway Consulting with regard to the amended CPV PPA and the conclusions reached in the firm’s independent evaluation. As described below, Sedway Consulting concluded that SCE acted in an appropriate, fair, and unbiased fashion in its negotiation of the amended CPV PPA and believes that the amended CPV PPA warrants CPUC approval. Sedway Consulting’s Role and Activities As noted above, Sedway Consulting was retained as the IE in SCE’s New Gen RFO. After the selection of final contracts and the regulatory process for approving them, Sedway Consulting continued to monitor back-and-forth New Gen-related emails between SCE and all counterparties with whom SCE executed New Gen PPAs. Specific to CPV, Sedway Consulting also performed the following tasks:

• participated in internal SCE calls/meetings related to the CPV’s circumstances and Priority-Reserve impacted New Gen projects in general,

• monitored update and negotiation calls/meetings between SCE and CPV regarding a proposed amended PPA,

• reviewed exchanges of redlined versions of the proposed amended CPV PPA,

• reviewed and commented on the scope of work for the Independent Engineer (Black & Veatch) that SCE retained to review the equipment procurement, construction, financing, and other elements of CPV’s Sentinel project to opine on whether the amended PPA’s new pricing was justified by changes associated with the project’s delay,

• reviewed confidential information provided by CPV to Black & Veatch,

• reviewed draft and final versions of Black & Veatch’s Independent Engineer report,

• performed an independent evaluation of CPV’s proposed PPA changes,

• participated in all SCE executive-level Risk Management Committee (RMC) meetings and PRG/CAM meetings in which CPV’s circumstances and proposed amended PPA were discussed.

Chronology of Events Following the execution of New Gen PPAs in March, 2008, Sedway Consulting kept abreast of developments and factors that might complicate the completion of projects associated with the New Gen PPAs. By June, 2008, some of the developers’ monthly progress reports were beginning to mention the Priority Reserve litigation but accorded it little likelihood of interfering with the air permitting process. However, in late July,


3

2008, the Los Angeles County Superior Court issued a decision that overturned the rules that the SCAQMD had developed to establish PM10 Priority Reserve emission offsets. This decision prevented CPV from acquiring the necessary air permits for the project to proceed. During the remainder of 2008 and into 2009, Sedway Consulting participated in SCE update meetings/calls to discuss the Priority Reserve developments and what strategies New Gen PPA counterparties might employ to move ahead on their projects. On October 20, 2009, Sedway Consulting participated in a call/meeting where CPV briefed SCE on the Sentinel project’s air permitting circumstances, given the recent (October 11, 2009) enactment of California Assembly Bill 1318 (AB1318). This legislation required SCAQMD to transfer sufficient PM10 offsets from its internal emission offset accounts to allow the development of eligible generation facilities that had current PPAs with California utilities. In effect, AB 1318 has provided CPV with a means to acquire the necessary PM10 offsets for the Sentinel facility’s air permits and continue the project’s development. However, the Priority Reserve complications had significantly delayed the Sentinel project’s development schedule and impacted its projected construction costs. CPV explained what it believed it could achieve regarding a new schedule (given the Priority Reserve lawsuits delay) for the entire eight-unit Sentinel project’s commercial operation date and the impact on the PPAs’ pricing. Obviously, any such changes were going to require the development of a PPA amendment. CPV indicated that it would need to move the project’s commercial operation dates from 2010/2012 to at least August, 2012. In early 2010, SCE undertook efforts to identify and retain the services of an Independent Engineer that would review confidential CPV materials and opine on whether the amended PPA’s new proposed pricing was justified by changes in equipment, construction, and financing costs that had occurred during the project’s delay. Ultimately, Black & Veatch was selected, and a kick-off call occurred on June 17, 2010. Following the meeting, CPV provided Black & Veatch and Sedway Consulting with the financial models and supporting documentation that stood behind the original PPAs’ pricing and the new amended PPA pricing. Negotiations on the wording of the amended PPA got underway during the summer of 2010. Negotiations proceeded until the execution of a final amended PPA on November 30, 2010. Details regarding the negotiations and the final terms and conditions of the amended PPA are discussed in Confidential Appendix B. Valuation of Amended PPA Sedway Consulting assessed the economic impacts of the amended PPA by evaluating its price changes and schedule shift in Sedway Consulting’s proprietary Response Surface Model (RSM). The RSM is a power supply evaluation tool that was used to conduct a parallel evaluation of all of the New Gen offers at each stage of SCE’s original


4

solicitation. A description of the RSM is provided in Appendix A. Sedway Consulting used all of the same market assumptions as were used in the RSM’s final analysis of offers when the original second CPV PPA was selected. Thus, Sedway Consulting’s cost estimates were different from SCE’s because SCE used its latest market assumptions. Sedway Consulting determined that the amended PPA is anticipated to result in increased costs (relative to the original PPAs), as depicted in Confidential Appendix B, but is likely to better match SCE’s resource needs. Specifically, the global economic downturn of the last several years has reduced SCE’s load forecast and delayed the need for new generation. Also, it is important to note that any valuation comparison with the original PPAs is somewhat academic as the Priority Reserve delay has made those original PPAs’ timelines unachievable. Assessment of Additional Amended PPA Provisions Beyond the capacity price reduction and the shifting of the project’s expected commercial operation date, there were several other PPA provisions that were modified. Sedway Consulting encouraged SCE and CPV to limit the number of these additional changes to the original PPAs. Sedway Consulting felt that accommodating the project’s schedule delay because of the Priority Reserve litigation should not be an opportunity to reopen or renegotiate unrelated portions of the PPAs. The original PPAs were the products of a competitive solicitation where SCE negotiated relatively consistent terms and conditions across numerous PPAs with counterparties that were competing for final selection. Sedway Consulting noted that it would be unfair to the unsuccessful participants of that process to allow CPV to shift risks in the original PPAs to SCE during these new negotiations without potentially retesting the marketplace and the revised provisions with a new solicitation. With that in mind, SCE exercised considerable resistance to CPV’s efforts to renegotiate and substantially revise portions of the original PPA that CPV wished to change. The details of the PPA changes are discussed in Confidential Appendix B. Conclusion Sedway Consulting monitored the PPA amendment negotiations and back-and-forth email traffic with CPV and believes that SCE pursued negotiations diligently with CPV while appropriately resisting CPV’s efforts to modify any provisions beyond those that had to be modified because of the shift in the project’s schedule or changes in circumstances since the original PPAs were executed. Sedway Consulting believes that SCE appropriately negotiated the amended CPV PPA and that the amended PPA warrants the CPUC’s approval.


A-1

Appendix A RSM Description and Numerical Example

The RSM is a power supply evaluation tool that uses the following information for each offer:

• Capacity • Commencement and expiration dates for power deliveries • Capacity pricing • Fuel pricing • Heat rates • Variable O&M pricing • Start-up costs and fuel requirements • Ancillary service capabilities • Transmission costs • Credit adders • Debt equivalence risk factor.1

All of the above information (if applicable) can be specified for any number of operating modes for any offer (e.g., base combined-cycle, duct-fired, power augmentation, etc.). The RSM is a spreadsheet-based tool that was calibrated to approximate the economic costs and benefits of each offer, based on the assumptions and representation of the southern California electricity and natural gas markets in SCE’s evaluation model. The RSM calculated each offer’s monthly fixed costs and net energy revenues, and developed a ranking of all offers. That ranking was based on the net levelized market value of each option, expressed in $/kW-month. An offer’s net market value was a combination of fixed and variable cost factors. On the fixed side, the RSM calculated monthly fixed costs associated with capacity payments, transmission costs, credit adders, and greenhouse gas (GHG) adders (even though the last such costs were not technically fixed in nature but were dependent on the degree that a proposed resource was called on for generation). In addition, the RSM calculated each offer’s value of capacity by multiplying a forecast of capacity value (developed from RA tag information acquired through SCE’s most recent All Source solicitation at the time of original PPA selection) by an offer’s RA capacity. This yielded a capacity benefit that was netted against an offer’s other fixed costs. These fixed costs and benefits were aggregated for each year into annual totals and discounted and converted into an equivalent levelized fixed price, expressed in $/kW-month. This was done by taking the

1 Debt equivalence was calculated for informational purposes only; CPUC policy at the time that the original CPV PPAs were selected for SCE’s New Gen RFO required that California utilities not include debt equivalence in their quantified evaluation metrics.


A-2

present value of the stream of costs and dividing it by the present value of the kW-months of capacity associated with the offer. On the variable cost side, the RSM developed estimates of the monthly net energy revenues and ancillary service revenues that SCE would be expected to realize if it acquired and scheduled a project’s generation. The net energy revenues are the difference between the revenues received from selling a project’s power into the market and the variable costs of generating that power. For a fully dispatchable project, SCE would be expected to schedule a resource to generate in all hours that the market price of electricity exceeded the resource’s $/MWh variable cost of generation. Thus, the net energy revenues for a proposed project represent the gains that would be realized from market sales after paying for a project’s fuel costs, variable O&M charges, and start-up costs. Ancillary service revenues were based on the capability and availability of evaluated resources to provide spinning and non-spinning reserves and a forecast of the expected prices for such ancillary services. The RSM estimated SCE’s net energy revenues for each month and each offer by interpolating between net energy revenue estimates that were extracted from a set of calibration runs from SCE’s detailed evaluation model. These runs were structured by Sedway Consulting and executed prior to the receipt of the New Gen final pricing proposals. Ancillary service revenues were developed by assessing which hours (if any) an option would be available for providing spinning or non-spinning reserves and multiplying the resource’s capacity by the expected price. The RSM then converted these annual net energy revenues and ancillary service revenues into a levelized $/kW-month value, using the same arithmetic process that was performed with the annual fixed costs. This conversion normalized the net energy and ancillary service revenues (i.e., accounted for the different amounts of capacity provided by each offer) and yielded a value that could be netted with the levelized fixed price in calculating each offer’s levelized net market value. The offers were ranked in descending order based on this levelized net market value. The top-ranked offers had the highest net levelized market value, representing those options with the lowest fixed costs, or the greatest net energy and ancillary service revenues, or a good combination of both. This net market value is similar to SCE’s $/kW-month net value metric, except for a calculation difference involving the use of summed versus discounted kW-months in the denominator of the calculation. This calculation difference did not introduce significant ranking or comparative differences within each selection year’s rankings in the original New Gen RFO, nor did it in the analysis of the amended CPV PPA. The following numerical example depicts the process that the RSM follows in developing its offer ranking. It is for illustrative purposes only. Assume that one has a one-year resource need of 250 MW and must select one of the two following offers:


A-3

Offer A Offer B Capacity 250 MW 250 MW Capacity Price $15.00/kW-month $11.67/kW-month Energy Price $52.50/MWh $72.50/MWh

Which one is more cost-effective? Assume that the RSM has been calibrated and populated with the following net energy revenue information for a 250 MW proxy resource as one-year market value statistics:2

• $23 million for a $50/MWh dispatch price resource • $21 million for a $55/MWh dispatch price resource • $14 million for a $70/MWh dispatch price resource • $12 million for a $75/MWh dispatch price resource

By interpolation, the RSM determines that the one-year net energy revenues are $22 million for Offer A and $13 million for Offer B. This is because the dispatch prices for the bids are halfway between the relevant calibration points; thus, the estimated net energy revenues are presumed to be halfway between the market value statistics for these calibration points. Converting these net energy revenues into $/kW-month equivalent values yields the following: $22M / (250 MW x 12 months) = $7.33/kW-month $13M / (250 MW x 12 months) = $4.33/kW-month The RSM calculates the net levelized market value of both bids by subtracting the fixed costs from the net energy revenues:

Offer A Offer B Net Energy Revenues $7.33/kW-month $4.33/kW-month Capacity Price $15.00/kW- month $11.67/kW-month Net Market Value -$7.67/kW-month -$7.34/kW-month

Offer B is more cost-effective; it has a higher (i.e., less negative) net market value. This can be confirmed through a total cost analysis as well. Offer A will require total capacity payments of $45 million, and Offer B will require approximately $35 million. Offer A will provide $9 million more in net energy revenues, but this is not enough to warrant paying $10 million more in capacity payments.

2 Note that this example is a simplification of the RSM’s calibration information. In practice, many more calibration points are used and represent an n-dimensional surface that incorporates heat rates, variable O&M charges, start-up costs and other parameters.

APPENDIX E CONFIDENTIAL (REDACTED)



Black & Veatch Corporation ⋅ 11401 Lamar ⋅ Overland Park, KS 66211 USA ⋅ Telephone: 913.458.2000

Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 8, 2010 Southern California Edison Company ATTN: Joe Jankosky 2244 Walnut Grove Avenue Rosemead, CA 91770

Subject: Review of Sentinel Proposed PPA Amendments

Attention: Joe Jankosky Mr. Jankosky: As requested, we have reviewed the proposed amendments to the Sentinel Project PPA and have provided opinion on the reasonableness of the cost differences between the existing 2008 PPAs and proposed 2010 PPA. Attached are our findings and references to supporting documentation, where appropriate. Very truly yours, BLACK & VEATCH

Page 2 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010

Background & Scope

Southern California Edison (SCE) launched a “New Generation RFO” in August 2006. Competitive Power Ventures (CPV) was a successful participant in both the fast-track and the standard-track of the New Generation RFO, and was awarded a 10-year tolling Power Purchase Agreement (PPA) for each of the Sentinel I and II Projects (Sentinel Project, or Project).

In July 2008 the Superior Court decision on Priority Reserve eliminated the Sentinel Project’s source of PM-10 and SOx offsets, and the Project was unable to move forward. In October 2009, the Governor of California signed AB1318 requiring the South Coast Air Quality Management District (SCAQMD) to transfer emission reduction credits in the full amount needed from the district’s internal bank upon receipt of payment of the mitigation fees. In October 2009, CPV approached SCE with revised pricing and a new estimated initial delivery date for the Sentinel Project.

In October 2010, SCE and CPV reconciled the existing PPAs for each of the Sentinel Projects into a single Agreement for the purposes of standardizing the terms of the Agreement between the two project segments. This revised and restated PPA effectively combines the two prior PPAs and allows for the Project segments to be treated as a single project. The proposed Sentinel Project is comprised of eight LMS100 turbines with a total capacity of | | | | | and expected initial delivery date (EIDD) of August 2013. The revised PPA provides for a possible extension of the EIDD to May 2014 in the event that the CPUC has not issued its final approval or if certain other conditions precedent specified in the PPA have not been met by June 30, 2011.

The California Public Utilities Commission (CPUC) requires supporting documentation when generators seek amendments to contracts that have been approved by the CPUC or terms that are significantly different from those proposed in their response to a solicitation prior to contract execution and submission to the CPUC for approval. As a result of the proposed pricing and schedule changes being significant from the prior agreement, it is necessary for these changes in capital cost to be assessed.


Black & Veatch was retained by SCE for the purpose of reviewing the revisions to the CPUC-approved Sentinel Project PPA with the objective of opining on the reasonableness of the proposed changes in contract pricing. Black & Veatch performed an initial review (August 13, 2010) on the changes in general market pricing for the development, construction, and financing of the Sentinel Project between the 2008 and 2010 PPAs. Additionally, Black & Veatch reviewed CPV’s financial model and cash flows used to determine the PPA pricing of the Sentinel Project as well as the impact the pricing has on CPV’s rate of return.

The initial report on Black & Veatch’s findings was issued on August 13, 2010. Subsequent to the issuance of this initial report, SCE and CPV entered in to a revised Agreement for the purchase of the power from the Sentinel Project. Black & Veatch has since revised the initial report to include the updated terms and pricing of the revised Agreement.

Project Overview

The proposed Sentinel Project will be located in Riverside County, California, approximately 5 miles North of Palm Springs (East of Los Angeles). The 37 acre site for the Project is under option for long term lease. The Sentinel Project consists of eight GE LMS100 gas-fired simple cycle combustion turbines with SCR and CO catalysts. Total plant output is | | | | | | and PPA contract capacity is 728 MW. Offsets for SOx, NOx, PM10, and VOC will be purchased to mitigate the Sentinel Project’s emissions.

The Project will connect to the CAISO transmission system at SCE’s Devers Substation; SCE will be the sole off-taker for electric generation from the Project during the term of the PPA. Project output is contracted to SCE via a 10-year tolling PPA. The natural gas fuel for the Project will come from SoCalGas, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

The Project’s LMS100 turbines include intercoolers which will be evaporatively cooled with conventional cooling towers. The cooling towers will utilize water sourced from on-site wells. Agreements have been made with

Page 4 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 various state and local water agencies for conservation and mitigation programs for the water consumption associated with the Project. Anticipated maximum plant water use is 1,100 acre-feet/year, to support a maximum dispatch factor of 30 percent. Wastewater produced by the Project will be treated with a zero liquid discharge treatment system to maximize re-use at the plant. Water makeup for evaporation and other losses will be replaced by water purchased from the Desert Water Agency. As part of the water purchase agreement, the Project will also fund the implementation of water conservation programs within the DWA service territory totaling approximately 1,500 acre-feet/year.

Analysis of Capital Cost Component Changes

The total Project capital cost includes costs for emissions offsets, engineering, procurement and construction (EPC) costs, financing costs, contingency, and other owner development and project costs. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

The major components to the capital cost change from the 2008 to 2010 PPAs are presented in Table 1 and Figure 1. The cost information for the 2008 PPA is presented as combined Phase I and Phase II costs, for the purposes of comparing equitable total plant outputs and costs between the prior and proposed PPAs.

The total cost increase from the 2008 to 2010 PPAs associated with these major line items is approximately | | | | | | | |. The major line items in Table 1 represent nearly all of the cost variation between the 2008 and 2010 PPAs | | | | | | | | | | | | | | | | with the remainder of the cost difference made up from a mixture of minor cost increases and decreases. It is important to note that the capital cost change between the 2008 and 2010 PPA for the imported water line item is a | | | | | | | | | | | | | | | | |. The cost change for each of these major line items is discussed in the sections below.


Table 1 Major Line Items for Capital Cost Change Between 2008 and 2010 PPAs

2008

($000) 2010

($000) Difference

($000) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

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Figure 1. Summary Distribution of Capital Cost Change Major Items

Emissions Offsets

The emissions offsets line item contributes the most | | | | | | | | | | | | | | | to the cost differential between the 2008 and 2010 PPAs. This cost difference stems mostly from the increasing costs of emissions offsets between the 2008 and 2010 time periods, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 1 Emission offset costs and associated volumes per pollutant are presented in Table 2.

1 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |


Table 2 Cost Allocations for Emissions Offset Categories for 2008 and 2010 PPAs

Emissions Offset Category 2008

($000) 2010

($000) Difference

($000) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

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Volumes for emissions offsets are required by permitting agencies and based on the Project’s “worst-case”, or maximum potential to emit, plant operation | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |. Changes in emissions volumes from the 2008 to 2010 PPA result from the documented refinement of the calculation for the emissions associated with the Project by the South Coast Air Quality Management District (SCAQMD)2. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Assumptions regarding the cost and volume for each of the emissions offset categories are presented in Table 3.

2 Refinements to emissions volumes in supplemental letters from South Coast AQMD dated July 15, 2010,as well as accompanying revisions to Appendix L (calculation of emissions volumes and costs).


Table 3 Emissions Volume and Offset Pricing

2008 2010 Change (%) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

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CPV has communicated that traditional, open market PM10 and SOx emission offsets are not available in sufficient quantity to support new large-scale electric generation facilities such as the Sentinel Project. As a result, the Sentinel Project and other new generators had planned to access the SCAQMD Priority Reserve offset program which, as amended in 2007, allowed new generators to obtain PM10 and SOx emission offsets in exchange for payment of mitigation fees to the SCAQMD. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |


In late 2008, the SCAQMD was sued; the outcome of the suit prevented it from issuing the Priority Reserve offsets to electric generation facilities. This effectively placed a moratorium on power plant development in Southern California. The Sentinel Project, in response, supported the passage of a bill in the California state legislature, which required the SCAQMD to issue PM10 and SOx emission internal bank offsets to entities which met certain criteria (the Sentinel Project met that criteria). The bill, AB1318, became effective on January 1, 2010 and maintains the pricing structure for these offsets as originally proposed by the SCAQMD.

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

The market for emissions offsets has been highly volatile and dependent on market demand for the offsets. Historical costs per pound for NOx emissions are shown in Figure 2. Because of the emissions offset cost increases, volatility, and market demand associated with the entrance of the Project to the emissions market, Black & Veatch believes that the estimates made by CPV for the pricing and associated escalations of emissions offsets for the 2010 PPA are reasonable, based on review of historical pricing.


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Figure 2. Historical NOX Price Observations

Total EPC / BOP

CPV has experienced cost increases for both EPC and Balance of Plant (BOP) line items between the submission of the 2008 and the proposal of the 2010 PPAs. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |


| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Black & Veatch finds the construction bid estimate from | | | | | | to be low compared to market. The escalation changes from the 2008 to the proposed 2010 PPA are reasonable, and in line with our experience with the construction market. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

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Table 4 Cost Allocations for EPC / BOP Categories for 2008 and 2010 PPAs

EPC / BOP Category 2008

($000) 2010

($000) Difference

($000) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

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Financing Fees & Closing Costs

Black & Veatch evaluated the financing fee and closing cost assumptions used by CPV for the 2010 pro forma with those anticipated for a new financing in the California peaking market and found the assumptions used in the proposed 2010 PPA to be reasonable, relative to current market conditions. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The Sentinel Project will require broad participation from the market and

Page 12 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 therefore the financing fees and rates may gravitate toward the higher end of the anticipated market range.

Black & Veatch has spoken with a lender familiar with the California market who indicated that Sentinel’s proposed capital structure and commitment fees are within the range of current expectations. Black & Veatch also believes that the credit spread assumptions used by CPV in the 2010 pro forma are reflective of current market conditions. With the knowledge that financial closing for the Sentinel Project may occur | | | | | | | | | | in the future, the lender with whom Black & Veatch consulted noted that upfront fees and credit spreads for well structured peaking projects with 10-year tolling agreements such as the Sentinel Project may be achievable in the | | | | | | | | | | | | | | | |. These values depend on market conditions at the time of financial close, and cannot be guaranteed.

Table 5 Financing Fees for 2008 and 2010 PPAs

2008 2010 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Development Cost

The value reported for development cost incurred in the 2010 PPA is significantly higher than that reported in the 2008 PPA. The ongoing and legal-intensive history of the Sentinel Project permitting has increased the time costs associated with the development of the Project (e.g. project management, legal, and environmental costs). The increase in total development cost is approximately | | | | | | | over the 2 to 3 year period of the delay between the 2008 and 2010 PPAs, which is not out of line with other projects with which Black & Veatch is familiar. CPV has provided a breakdown for the budgeted development costs of the Project, presented in Table 6.


Table 6 Budgeted Development Costs for 2008 and 2010 PPAs

2008

($000) 2010

($000) Difference

($000) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

The costs incurred to-date as well as the quarterly forecasted costs for the development of the Sentinel Project are presented in Table 7. To-date (1st quarter 2010) the Project has incurred | | | | | | | | | | in development costs, which accounts for | | | | | | | | | of the total budgeted development costs for the Project. Black & Veatch finds the incurred and projected development costs for the Project to be reasonable.


Table 7 Incurred and Forecast Development Costs for 2010 PPA

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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Sales Taxes

The overall capital cost increase associated with the sales taxes has resulted from a slightly higher sales tax rate. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The sales tax basis, rates, and total sales taxes for each of the PPAs are presented in Table 8.


Table 8 Sales Tax Amounts for 2008 and 2010 PPAs

2008 2010 Difference | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Water Interconnect

The water interconnect cost increase from the 2008 to the 2010 PPAs results from actual well drilling capital costs to be incurred, as well as an increase in the anticipated number of on-site wells for Project water use. Contractual water reclamation and conservation costs have a documented increase over the period between the two PPAs of | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Black & Veatch finds that the amount budgeted for the on-site wells to be reasonable.

CPV has entered into a water conservation funding agreement with the Desert Water Agency (DWA) for the purposes of mitigating water use by the Sentinel Project. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The terms of the agreement include the following items:

• | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

• | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |


An amendment to the water conservation funding agreement has stated that the costs associated with the reclamation and conservation efforts have increased from | | | | | | | | | | | | | | | | | | | | | | in the time period between the 2008 and 2010 PPAs. This change is reflected in an increase in the costs presented in Table 9.

Black & Veatch considers the capital costs for drilling the site test well and the amount budgeted for permanent plant wells to be reasonable, and acknowledges the documentation for the cost increases associated with reclamation and conservation efforts executed with DWA.

Table 9 Water Interconnect Costs for 2008 and 2010 PPAs

2008

($000) 2010

($000) Difference

($000) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Electrical Interconnect

Electrical interconnection costs have increased between the 2008 and 2010 PPAs. The gen-tie cost increase from | | | | | | | | | | | | | is documented in an amendment to the Large Generator Interconnection Agreement (LGIA) between SCE and the Project dated October 12, 20073| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Interconnection taxes increase by | | | | | | | | as a result of the gen-tie cost increase. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The electrical interconnect cost assumptions for the 2008 and 2010 PPAs are presented in the table below, and are considered reasonable.

3 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |


Table 10 Electrical Interconnect Costs for 2008 and 2010 PPAs

2008

($000) 2010

($000) Difference

($000) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Contingency

CPV has assumed a | | | | | | | | | | | | | | | | | | | | for the development of the Sentinel Project for each of the 2008 and 2010 bid models. The increase in this cost is a necessary reaction to the increasing capital costs of the Project. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | this assumption is considered reasonable and within the range that Black & Veatch would expect for a project of this size and type.

Imported Water (Cost Decrease)

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | CPV has entered into a water supply agreement with DWA for the purposes of acquiring water to be used by the Sentinel Project. The agreement between CPV and DWA has the following terms, among others:

• | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

• | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

• | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |


| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Table 11 Imported Water Costs for 2008 and 2010 PPAs

2008 2010 Difference | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

ROE and ROI analysis (Including residual value assumption)

The cash flows for both the construction period and operation period were evaluated in order to verify the rate of return calculated by CPV for each of the PPAs. The construction cash flows included equity portions of fees, IDC, and Equity Bridge Loan Interest, where applicable. Cash flow analysis for the operational period included the consideration of after-tax cash flows during the PPA merchant period as well as the replacement cost assumption for the value of the plant through the end of its operational life.

The major assumptions for the calculation of the rate of return, as well as the calculated and independently verified rate of return for the Project are presented in the table below. Black & Veatch has evaluated the calculation of the after-tax levered IRR for the PPAs and finds the methodology used to be acceptable. Black & Veatch is of the opinion that the 2010 PPA after-tax levered IRR of | | | | | | is below the customary range of equity returns for similar

Page 19 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 development projects. Major assumptions used for the calculation of the return on equity for each of the PPAs is presented in Table 12.

Table 12 Major Assumptions Used for the Calculation of Return on Equity

2007 2008 2010 2010 Delayed

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Delayed EIDD Provision

The revised PPA provides for a possible extension of the EIDD to May 2014 in the event that the CPUC has not issued its final approval or if certain other conditions precedent specified in the PPA have not been met by June 30, 2011. Accordingly, there are certain capital cost line items that would experience escalation between the initial August 2013 EIDD and May 2014 EIDD. CPV has provided estimates of these expected cost increases associated with the delayed 2014 EIDD. Black & Veatch has reviewed major line items and their associated escalation and/or additional incurred costs over the nine month interval between the two EIDDs. Black & Veatch found that the Project capital cost incurs escalation and cost increases | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | As a result, the Project is expected to earn a lower internal rate of return in the delayed EIDD scenario than if the

Page 20 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 Project were to meet the initial EIDD. A summary table of the capital cost increase and IRR are presented in Table 13. Black & Veatch finds the escalation and cost increases applied to the modeling of the delayed PPA IRR to be reasonable.

Table 13

Residual Value Assumptions for 2010 PPA

2010 Proposed EIDD

2010 Delayed EIDD

Change (%)

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

2010 PPA Residual Value Assumption

CPV has provided the following reasoning and calculation for the establishment of the | | | | | | | | | | residual value of the Project. This residual value makes up the entirety of the Project’s cash flows from the end of the 10-year tolling agreement with SCE proposed in the 2010 PPA to the end of the 30-year operational life of the project. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | The energy margin component of the residual cost is stated to be based on a 4-year historical back-cast of SP15 and SoCal Border daily prices from 2004-2007. The capacity component is stated to be based on an analysis of LCRA transactions in the LA Basin since 2007. These assumptions are presented in Table 14.

Table 14 Residual Value Assumptions for 2010 PPA

2008 2023*

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Reasonableness of Capacity Value

CPV has communicated that the fixed costs for the Project in the 2010 PPA are approximately | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |. From a market

Page 21 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 perspective, the fixed costs for the Project represent the absolute minimum capacity payment that the Project would need to receive in order to remain in operation, assuming no debt service or equity return. Black & Veatch finds the current assumption of a capacity component of the residual cost of | | | | | | | | | | | | to be near the minimum required level to remain in the market and comparable with current market valuation for capacity. The escalation of the capacity value from | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | is considered acceptable. The | | | | | | | | | | fixed cost is also found to be in-line with the fixed costs of comparable plant configurations.

Reasonableness of Energy Margin

The energy margin component of the residual value assumption from the 2010 proposed PPA for the Project produces a calculated | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |. Based on information gathered from the Energy Information Association (EIA) and Project performance data regarding energy production and heat rate, Black & Veatch calculated the anticipated energy margin of approximately | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |. It should be noted that this estimate is based on energy and fuel price forecasts for the entire WECC region, rather than regionally specific to the Sentinel project. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | If a lower energy margin is realized, then the residual value of the Project will be lower than the value used in the 2010 PPA pro forma. Table 15 shows the relevant assumptions used to calculate the energy margin for the Sentinel Project using EIA information.


Table 15 Calculated Energy Margin Using EIA Fuel and Energy Price Information

2008 2023 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Market Assumptions

The analyses above are based on the assumption that the capacity market in SCE will maintain separate pricing for new and existing units. If the market should become a single-price capacity market, then the Project will be bidding for capacity based on the marginal price of a new unit at the end of the tolling period. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 4. These calculations provide a rough feasible range of possible project capacity payments for the continued operation of the plant past the expiration of the 10-year tolling agreement. As such, the

4 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Page 23 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 current residual value appears to be conservative, however, a lower value could still be realized if the energy margin is less than currently forecast.

However, if the capacity market changes towards capacity prices equitable to the Cost Of New Entrants (CONE), then the residual value of the Project could be significantly higher, which would occur if the current market structure changes to allow existing generators to bid for new generation PPAs. This will push the capacity price upward as market demand for capacity increases, and the capacity price for existing units will approach that of new units. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Black & Veatch has reviewed the reasonableness of the residual value of the plant assumption in the proposed 2010 PPA as well as the existing 2007 and 2008 PPAs and found that under the consideration of a bifurcated market structure for new and existing units in SCE (that the current practice of price discrimination is in full effect at the end of the tolling agreement), then the residual value assumption of | | | | | | | | | | | is appropriate. If the market moves away from a bifurcated market structure, then the residual value assumption of | | | | | | | | | | | would be appropriate.

Summary of PPA Contract Changes CPV has requested the following amendments to the 2007 and 2008 PPAs:

• Rescheduling of Expected Initial Delivery Date (EIDD) to August 1, 2013.

• Revised Monthly Capacity Prices to reflect the amended EIDDs.

• Inclusion of a provision for a delayed EIDD in the event that the CPUC has not issued its final approval or if certain other conditions precedent specified in the PPA have not been met by June 30, 2011.


Table 16 PPA Contract Summary for 2007, 2008, 2010

2007 PPA

(Units 1 - 5) 2008 PPA

(Units 6 - 8)

2010 Proposed

PPA

2010 Delayed

PPA | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |

Black & Veatch finds that these proposed contract changes capture the cost and schedule changes that have impacted the Sentinel projects.

Permitting Matrix Summary

Black & Veatch conducted a review of the permitting information submitted by CPV for the Sentinel Project, as well as available information for the Project from the California Energy Commission (CEC). According to the information from the CEC, the project was delayed because it did not have enough Emission Reduction Credits (i.e., offsets) in 2008. Project information indicates that the South Coast Air Quality Management District (SCAQMD) has set aside the emission offsets for the Project in a separate tracking account and submitted the necessary information to the CEC's certification process for environmental review and approval. CEC information also indicates that another key issue associated with the project - water supply - has been resolved through the development of a water supply plan that appears to have been accepted by both the CEC and Project stakeholders. The CEC staff has issued its Final Staff Assessment recommending Certification of the Project. The project is currently involved in hearings and appears to be on track for receiving certification from the CEC. This supports information regarding the permitting process of the Project that has

Page 25 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 been provided by CPV, and Black & Veatch finds the progress and anticipated timing communicated in the permitting matrix to be reasonable.

There may need to be additional federal, state, or local permits or authorizations required for the construction or operation of the Project, such as a National Pollutant Discharge Elimination System (NPDES) stormwater permit. Black & Veatch believes that these additional permits are relatively minor and should not be of such significance or difficulty to obtain to be a hindrance to the construction or operation of the Project. A list of the major Project permits and the agency is presented in Table 17.

Table 17

List of Major Project Permits and Agency Issue Agency CEC Certification (07-AFC-03) CEC SIP Revision to Implement AB 1318 (2009, V.M. Perez), Health and Safety Code 40440.14

SCAQMD / CARB / EPA Region 9

SIP Revision of SCAQMD Federal PM10 Redesignation Request and Maintenance Plan for the Coachella Valley SCAQMD / CARB / EPA Region 9

NRDC vs SCAQMD 9th Circuit Court of Appeals (Federal) CCAT et. al. vs CEC & SCAQMD CA Superior Court EPA Response to Petition for SIP rule for SB 827 and AB 1318 EPA Region 9

EPA NO2 1 hr standard EPA Headquarters EPA SO2 1 hr standard EPA Headquarters

Conclusions

Black & Veatch has reviewed relevant documents, validated financial model calculations, and spoken with representatives from CPV regarding the issues outlined in this report for the increase of the capacity payment for the proposed 2010 PPA. Black & Veatch finds the overall capacity price assumption of | | | | | | | | | | to be representative of the actual and expected cost changes that have impacted the project.

However, as shown in Table 12, the capacity price assumption of | | | | | | | | | | | | | | (as escalated to reflect the amended EIDD) results in a below-market after-tax equity IRR of | | | | | | for the Proposed 2010 PPA, based on a relatively conservative residual value assumption of | | | | | | | | |. Black & Veatch finds that

Page 26 Southern California Edison B&V Project 168654 Review of Sentinel Proposed PPA Amendments November 3, 2010 the | | | | | | | | | | | residual value assumption is reasonable, but as stated earlier, the residual value of the Project could be higher.

Further, Black & Veatch has found that all but approximately | | | | | | | | | | of the cost difference between the 2008 and 2010 PPA can be considered as “hard” documented costs | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |. The | | | | | | in remaining costs consists of the forecast additional development cost | | | | | | | | | |, the anticipated costs of the on-site water wells | | | | | | | | | | |, and the yet-to-be obtained balance of VOC credits and NOX credits | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |. Black & Veatch considers the estimated costs for the on-site wells to be reasonable and inline with our expectations. The emissions credit estimated cost is outside of the project’s control, and would be expected to impact a similar project to the same magnitude. The overall project cost is in line with or below Black & Veatch’s expectations for a plant of this size and type located in California.

CERTIFICATE OF SERVICE

I hereby certify that, pursuant to the Commission’s Rules of Practice and Procedure, I

have this day served a true copy of PETITION OF SOUTHERN CALIFORNIA EDISON

COMPANY (U 338-E) FOR MODIFICATION OF DECISION 08-09-041 on all parties

identified on the attached service list(s). Service was effected by one or more means indicated

below:

Transmitting the copies via e-mail to all parties who have provided an e-mail address.

First class mail will be used if electronic service cannot be effectuated.

Executed this 16th day of December, 2010, at Rosemead, California.

/s/ Norma Perez By: Norma Perez

SOUTHERN CALIFORNIA EDISON COMPANY 2244 Walnut Grove Avenue Post Office Box 800 Rosemead, California 91770

PROCEEDING: A0804011 - EDISON - FOR APPROVA FILER: SOUTHERN CALIFORNIA EDISON COMPANY LIST NAME: LIST LAST CHANGED: OCTOBER 28, 2010

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CATHY A. KARLSTAD NOEL OBIORA SOUTHERN CALIFORNIA EDISON COMPANY CALIF PUBLIC UTILITIES COMMISSION 2244 WALNUT GROVE AVE. LEGAL DIVISION ROSEMEAD, CA 91770 ROOM 4107 FOR: SOUTHERN CALIFORNIA EDISON COMPANY 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 FOR: DRA

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NRG ENERGY 2928 2ND AVENUE 5790 FLEET STREET, SUITE 200 SAN DIEGO, CA 92103 CARLSBAD, CA 92008 LARRY KOSTRZEWA MARK TURNER EDISON MISSION ENERGY DIRECTOR 18101 VON KARMAN AVENUE, STE 1700 COMPETITIVE POWER VENTURES, INC. IRVINE, CA 92612 55 2ND STREET, SUITE 525 SAN FRANCISCO, CA 94105 WILL MITCHELL BRIAN T. CRAGG COMPETITIVE POWER VENTURES, INC. GOODIN, MACBRIDE, SQUERI, DAY & LAMPREY 55 2ND STREET, SUITE 525 505 SANSOME STREET, SUITE 900 SAN FRANCISCO, CA 94105 SAN FRANCISCO, CA 94111 DIANE I. FELLMAN CALIFORNIA ENERGY MARKETS DIRECTOR, REGULATORY & MARKET AFFAIRS 425 DIVISADERO STREET, STE 303 NRG WEST SAN FRANCISCO, CA 94117 73 DOWNEY STREET SAN FRANCISCO, CA 94117 DOUGLAS DAVIE RYAN BERNARDO WELLHEAD ELECTRIC COMPANY BRAUN BLAISING MCLAUGHLIN, P.C. 650 BERCUT DRIVE, SUITE C 915 L STREET, SUITE 1270 SACRAMENTO, CA 95814 SACRAMENTO, CA 95814 SCOTT BLAISING BRAUN BLAISING MCLAUGHLIN P.C. 915 L STREET, STE. 1270 SACRAMENTO, CA 95814

MATTHEW DEAL MELANIE DARLING CALIF PUBLIC UTILITIES COMMISSION CALIF PUBLIC UTILITIES COMMISSION POLICY & PLANNING DIVISION DIVISION OF ADMINISTRATIVE LAW JUDGES ROOM 5119 ROOM 5041 505 VAN NESS AVENUE 505 VAN NESS AVENUE SAN FRANCISCO, CA 94102-3214 SAN FRANCISCO, CA 94102-3214

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LAW-#1779333-v1-A0804011 PFM for CPV Amendment Public...As the result of a ruling in a lawsuit filed against the South Coast Air Quality Management District (“SCAQMD”), however,