PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

I.D. #7088

ENERGY DIVISION RESOLUTION E-4128

November 16, 2007

REDACTED

RESOLUTION

Resolution E-4128. Pacific Gas and Electric (PG&E) Company requests approval of a renewable resource procurement contract resulting from its 2006 RPS solicitation. This contract is approved without modification.

By Advice Letter 3090-E filed on July 20, and Supplemental Advice Letter 3090-E-A filed on August 10, 2007

__________________________________________________________

SUMMARY

PG&E's renewable contract complies with the Renewables Portfolio Standard (RPS) procurement guidelines and is approved without modification

PG&E's renewable contract complies with the Renewables Portfolio Standard (RPS) procurement guidelines and is approved. PG&E's request for approval of a renewable resource procurement contract is granted pursuant to Decision (D.) 06-05-039. The energy acquired from this contract will count towards PG&E's Renewables Portfolio Standard (RPS) requirements.

Deliveries from the power purchase agreement (PPA) and shaping and firming agreement (collectively, the Agreements) are priced below the 2006 market price referent (MPR) and thus do not require supplemental energy payments from the California Energy Commission.¹

Confidential information about the contract should remain confidential

This resolution finds that certain material filed under seal pursuant to Public Utilities (Pub. Util.) Code Section 583, General Order (G.O.) 66-C, and D.06-06-066 should be kept confidential to ensure that market sensitive data does not influence the behavior of bidders in future RPS solicitations.

BACKGROUND

The RPS Program requires each utility to increase the amount of renewable energy in its portfolio

The California Renewables Portfolio Standard (RPS) Program was established by Senate Bill 1078² and codified by California Pub. Util. Code Section 399.11, et seq. The statute required that a retail seller of electricity such as PG&E purchase a certain percentage of electricity generated by Eligible Renewable Energy Resources (ERR). Originally, each utility was required to increase its total procurement of ERRs by at least 1 percent of annual retail sales per year until 20 percent is reached, subject to the Commission's rules on flexible compliance, no later than 2017.

The State's Energy Action Plan (EAP) called for acceleration of this RPS goal to reach 20 percent by 2010.³ This was reiterated again in the Order Instituting Rulemaking (R.04-04-026) issued on April 28, 2004,⁴ which encouraged the utilities to procure cost-effective renewable generation in excess of their RPS annual procurement targets (APTs)⁵, in order to make progress towards the goal expressed in the EAP. On September 26, 2006, Governor Schwarzenegger signed Senate Bill (SB) 107,⁶ which officially accelerates the State's RPS targets to 20 percent by 2010, subject to the Commission's rules on flexible compliance⁷.

CPUC has established procurement guidelines for the RPS Program

The Commission has issued a series of decisions that establish the regulatory and transactional parameters of the utility renewables procurement program. On June 19, 2003, the Commission issued its "Order Initiating Implementation of the Senate Bill 1078 Renewable Portfolio Standard Program," D.03-06-071. On June 9, 2004, the Commission adopted its Market Price Referent (MPR) methodology⁸ for determining the Utility's share of the RPS seller's bid price, as defined in Pub. Util. Code Sections 399.14(a)(2)(A) and 399.15(c). On the same day the Commission adopted standard terms and conditions for RPS power purchase agreements in D.04-06-014 as required by Pub. Util. Code Section 399.14(a)(2)(D). Instructions for evaluating the value of each offer to sell products requested in a RPS solicitation were provided in D.04-07-029.

More recently, on December 15, 2005, the Commission adopted D.05-12-042 which refined the MPR methodology for the 2005 RPS Solicitation.⁹ Subsequent resolutions adopted MPR values for the 2005, 2006 and 2007 RPS Solicitations.¹⁰

In addition, D.06-10-050, as modified by D.07-03-046, further refined the RPS reporting and compliance methodologies.¹¹ In this decision, the Commission established methodologies to calculate an LSE's initial baseline procurement amount, annual procurement target (APT) and incremental procurement amount (IPT).¹²

California Energy Commission (CEC) certifies out-of-state facilities for RPS compliance

The CEC is responsible for certifying the RPS-eligibility of renewable facilities located out-of-state which have their first point of interconnection to the WECC transmission system. The guidelines for certifying out-of-state facilities can be found in the CEC's Renewables Portfolio Standard Eligibility Guidebook.¹³ See Attachment B for more information regarding the CEC's guidelines.

Interim Greenhouse Gas Emissions Performance Standard (EPS) established emission rate limitations for long-term electricity procurement

A greenhouse gas emissions performance standard (EPS) was established by Senate Bill 1368¹⁴, which requires that the Commission consider emissions costs associated with new long-term (five years or greater) power contracts procured on behalf of California ratepayers.

On January 25, 2007, the Commission approved D.07-01-039 which adopted an interim EPS that establishes an emission rate quota for obligated facilities to levels no greater than the GHG emissions of a combined-cycle gas turbine (CCGT) powerplant.¹⁵ The EPS applies to all long-term energy contracts for baseload generation.¹⁶ Renewable energy contracts are deemed EPS compliant from the EPS except in cases where intermittent renewable energy is shaped and firmed with generation from non-renewable resources. If the renewable energy contract is shaped and firmed with a specified energy source that is considered baseload generation, then the energy source must individually meet the EPS. If, however, the intermittent energy is firmed and shaped with an unspecified energy source (e.g. system power), then D.07-01-039 specifically defines the following eligibility condition:¹⁷

For specified contracts with intermittent renewable resources (defined as solar, wind and run-of-river hydroelectricity), the amount of substitute energy purchases from unspecified resources is limited such that total purchases under the contract (whether from the intermittent renewable resource or from substitute unspecified sources) do not exceed the total expected output of the specified renewable powerplant over the term of the contract.

PG&E requests approval of a renewable energy contract

On July 20, 2007, PG&E filed Advice Letter (AL) 3090-E requesting Commission approval of a renewable procurement contract between PG&E and PPM Klondike III Wind Power (Klondike). On August 10, 2007, PG&E filed Supplemental AL 3090-E-A to include the Independent Evaluator's Report for PG&E's 2006 RPS Solicitation. The PPA includes a shaping and firming agreement with PPM Energy, Inc. (PPM) The PPA results from PG&E's 2006 RPS solicitation which was authorized by D.06-05-039 on May 25, 2006. The Commission's approval of the PPA will authorize PG&E to accept future deliveries of incremental supplies of renewable resources and contribute towards the 20 percent renewables procurement goal required by California's RPS statute.¹⁸ On August 1, 2007, PG&E reported its IPT for 2006 as 727 GWh.¹⁹ With the approval of this PPA, PG&E will have contracted for 265 GWh towards that target.

PG&E requests final "CPUC Approval" of Contract

PG&E requests the Commission to issue a resolution containing the findings required by the definition of "CPUC Approval" in Appendix A of D.04-06-014. In addition, PG&E requests that the Commission issue a resolution that finds the following:

1. Approves the Agreements in their entirety, finds that PG&E's execution of the Agreements are reasonable and in the public interest, and finds that PG&E's payments under the Agreements are reasonable and are fully recoverable in rates over the life of the contract, subject to CPUC review of PG&E's administration of the Agreements.

2. Finds that any procurement pursuant to the Agreements is procurement from an eligible renewable energy resource for purposes of determining PG&E's compliance with any obligation that it may have to procure eligible renewable energy resources pursuant to the California Renewables Portfolio Standard (Public Utilities Code Section 399.11 et seq.), D.03-06-071, or other applicable law;

3. Finds that there is a risk that deliveries will not occur as described by the Agreements due to factors that are beyond PG&E's control; that PG&E has made reasonable attempts to reduce the risk of non-performance associated with the PPA without unduly increasing its cost of procurement under the PPA; and that PG&E shall not be subject to penalties for RPS delivery shortfalls due to non-performance of a seller under the PPA, consistent with previous decisions.

4. Finds that payments made under the Agreements and any indirect costs of renewables procurement identified in Section 399.15(d) shall be fully recoverable in rates over the life of the Agreements.

5. Finds that any cost of bringing generation from the delivery point to PG&E's load center shall be fully recoverable in rates over the life of the Agreements.

6. Finds that any stranded costs that may arise from the Agreements are subject to the provisions of D.04-12-048 that authorize stranded cost recovery over the life of the contract. Implementation of these provisions will be addressed in Rulemaking 06-02-013.

PG&E's Procurement Review Group participated in review of the contract

In D.02-08-071, the Commission required each utility to establish a "Procurement Review Group" (PRG) whose members, subject to an appropriate non-disclosure agreement, would have the right to consult with the utilities and review the details of:

1. Overall transitional procurement strategy;

2. Proposed procurement processes including, but not limited to, RFO; and

3. Proposed procurement contracts before any of the contracts are submitted to the Commission for expedited review.

The PRG for PG&E consists of: California Department of Water Resources (DWR), the Commission's Energy Division, Natural Resources Defense Council (NRDC), Union of Concerned Scientists (UCS), Division of Ratepayer Advocates (DRA), Aglet Consumer Alliance (Aglet), Coalition of California Utility Employees (CUE) and The Utility Reform Network (TURN).

PG&E provided its PRG with reports on Klondike on several occasions. On September 25, 2006, PG&E presented the PRG with the results of its 2006 RPS solicitation, and discussed its shortlist on October 26, 2006. Updates on the negotiations with Klondike and the associated shaping and firming agreement were provided to the PRG on December 14, 2006, January 26, 2007, March 30, 2007, and May 30, 2007.

The PRG members have expressed general satisfaction with the manner in which PG&E arrived at its 2006 shortlist and the resulting PPAs. Members of the PRG did not object to PG&E's decision to execute the Agreements presented with this Advice Letter. Although Energy Division is a member of the PRG, it reserved its conclusions for review and recommendation on the PPA to the resolution process.

NOTICE

Notice of AL 3090-E and Supplemental AL 3090-E-A were made by publication in the Commission's Daily Calendar. PG&E states that a copy of the Advice Letter was mailed and distributed in accordance with Section III-G of General Order 96-A.

PROTESTS

PG&E's Advice Letter (AL) 3090-E was timely protested on August 9, 2007 by Merced Irrigation District and Modesto Irrigation District (Districts) and The Utility Reform Network (TURN).

While the Districts did not object to the terms of the PPA, the Districts objected to PG&E's request for approval of stranded cost recovery in connection with the PPAs. The Districts state that the issue regarding implementation of stranded cost recovery, pursuant to D.04-12-048,²⁰ is presently being considered by the Commission in the long-term procurement proceeding R.06-02-013.

TURN did not object to the terms of the PPA or the shaping and firming agreement. TURN protested AL 3090-E on the grounds that insufficient information was provided to determine compliance with California's Emissions Performance Standard (EPS) as defined by Senate Bill (SB) 1368 and D.07-01-039. Specifically, TURN states that it is unclear if the shaping and firming agreement prevents PPM from delivering power from specified sources with high levels of greenhouse gasses to PG&E under the terms of the PPA, which would be in conflict with EPS compliance rules.

On August 16, 2007, PG&E responded to the protests from the Districts and TURN. In response to the Districts protest, PG&E stated that AL 3090-E requests that the Commission only affirm that above-market costs are eligible for recovery from all customers over the life of the contracts, consistent with Commission policy in D.04-12-048. In response to TURN's protest, PG&E states the Agreements with Klondike and PPM comply with the EPS on the grounds that the generation is from an RPS-eligible wind facility, that the intermittent generation will be firmed with unspecified system power, and that the quantity of generation imported will not exceed generation output per the PPA.

DISCUSSION

Description of the project

The following table summarizes the substantive features of the Contract. See confidential Appendix C for a detailed discussion of contract terms and conditions:

PPA is consistent with PG&E's CPUC adopted 2006 RPS Plan

California's RPS statute requires the Commission to review the results of a renewable energy resource solicitation submitted for approval by a utility.²¹ PG&E's 2006 RPS procurement plan (Plan) was approved by D.06-05-039 on May 25, 2006. Pursuant to statute, the plan includes an assessment of supply and demand to determine the optimal mix of renewable generation resources, consideration of flexible compliance mechanisms established by the Commission, and a bid solicitation protocol setting forth the need for renewable generation of various operational characteristics.²²

The stated goals of PG&E's 2006 Plan was to procure approximately 1-2 percent of retail sales volume or between 727 and 1,454 GWh per year, with delivery terms of 10, 15, or 20 years. Participants could submit offers for four specific products - as-available, baseload, peaking and/or dispatchable resources. The PPA is consistent with PG&E's goal of procuring energy from projects with deliveries expected to contribute towards 20% renewables in 2010.

PPA selection consistent with RPS Solicitation Protocol

The PPA is consistent with the RPS plan because it was achieved through PG&E's adherence to its CPUC approved Solicitation Protocol:

1. PG&E generally followed the RPS Solicitation schedule set forth in its Solicitation Protocol, but ultimately, the schedule for concluding negotiations was necessarily extended.²³

2. Using the approved bid solicitation protocol and forms of power purchase agreements, PG&E commenced its solicitation on June 30, 2006. Bids were received until September 8, 2006, consistent with the published schedule. All of the accepted bids conformed to the RPS protocol; that is, they offered power from eligible renewable energy resources, they were submitted using the standard forms, they executed the bid protocol and confidentiality agreements, and they posted the required bid deposit. One bid was disqualified because of its reliance on natural gas at levels greater that the CEC's eligibility requirements for hybrid projects.

3. These bids were evaluated and scored in the manner prescribed in the Solicitation Protocol. In particular, evaluation of the offer price took into account PG&E's published Time of Delivery factors and imputed the potential cost of transmission adders. PG&E scored the offers pursuant to a methodology that attributed the proper weight to market valuation, portfolio fit, credit and other non-price factors of the Solicitation Protocol.

4. The bids were ranked according to the protocols, and were placed on PG&E's "Short List" and presented to PG&E's PRG on October 26, 2006. PG&E notified short-listed bidders and PG&E negotiations with short-listed bidders began once they submitted the required bid deposit. The interim results of negotiations were presented to the PRG on several occasions between December 14, 2006 and May 30, 2007. At those meetings, PRG members discussed the importance that the Klondike contract ensures compliance with the emissions performance standard, no PRG members objected to PG&E proceeding to execute the PPA presented by this advice letter.

5. PG&E submitted its "Shortlist Report" to the CPUC on December 22, 2006.²⁴ The Shortlist Report consists of PG&E's Least-Cost Best-Fit Evaluation report, the Independent Evaluator's report and PG&E's confidential Shortlist selection. PG&E's Shortlist Report conformed to the format developed by Energy Division Staff.

Bid evaluation process consistent with Least-Cost Best Fit (LCBF) criteria

The LCBF decision²⁵ directs the utilities to use certain criteria in their bid ranking. Specifically, the decision offers guidance regarding the process by which the utility ranks bids in order to select or "shortlist" the bids with which it will commence serious negotiations. Much of the bid ranking criteria described in the LCBF decision is incorporated in PG&E's Solicitation Protocol and is discussed below.

The Commission has issued several decisions that require PG&E to employ an Independent Evaluator (IE) in RPS Solicitations.²⁶ On December 22, 2006, PG&E submitted its 2006 Shortlist Report which included a report from the IE employed to oversee PG&E's 2006 RPS Solicitation. The IE report provided an assessment of PG&E's 2006 RPS Solicitation and specifically addressed the design and administration of PG&E's LCBF evaluation process, and the reasonableness of PG&E's shortlist selections. PG&E's IE concluded in its report that PG&E performed reasonable outreach activities for its 2006 Solicitation, and provided adequate guidance for potential bidders on its website and at its open pre-solicitation bidder's conference.²⁷ The IE report also stated that PG&E conducted a fair, consistent and effective evaluation of the offers without bias, and made the appropriate selection decisions in its 2006 RPS Solicitation Shortlist.

Market Valuation

In its "mark-to-market analysis," PG&E compares the present value of the bidder's payment stream with the present value of the product's market value to determine the benefit (positive or negative) from the procurement of the resource, irrespective of PG&E's portfolio. Offer benefits are the market value of the energy, capacity, and ancillary services. PG&E evaluates the bid price and indirect costs, such as debt equivalence, and the costs to the utility transmission system caused by interconnection of the resource to the grid or integration of the generation into the system-wide electrical supply.²⁸ The benefit/cost analysis yields a Net Market Value; a $/MWh comparison of the value of generation from a proposed contract and PG&E's forward curve, or its proxy for firm system energy.

Portfolio Fit

Portfolio fit considers how well an offer's features match PG&E's portfolio needs, with special consideration of project online and generation profile. This analysis includes the anticipated transaction costs involved in any energy remarketing (i.e., the bid-ask spread) if the contract adds to PG&E's net long position. Because these deliveries are anticipated to occur at a time when PG&E is experiencing moderate need for baseload energy, the acceptance of these baseload deliveries should not result in significant remarketing costs.

Consideration of Transmission Adders

The RPS statute requires the "least cost, best fit" eligible renewable resources to be procured. Under the RPS program, the potential customer cost to accept energy deliveries from a particular project must be considered when determining a project's value for bid ranking purposes. PG&E's 2006 transmission ranking cost report (TRCR)²⁹ identified the remaining available transmission capacity and upgrade costs for PG&E substations at which renewable resources are expected to interconnect. PG&E determined the TRCR cluster at which each shortlisted project would interconnect to the transmission grid. Consistent with Commission Decisions, based on the potential transmission congestion, the associated proxy transmission network upgrades and the associated capital costs that may be need to accommodate delivery at this cluster, PG&E assigned a transmission adder to each Offer for evaluation.

Terms and conditions of delivery

PPM, or its agent, will be the scheduling coordinator for the project throughout the delivery term and the point of delivery will be COB.

Transmission upgrades

All necessary transmission upgrades have been completed.

Consistency with Adopted Standard Terms and Conditions

The Commission set forth standard terms and conditions to be incorporated into RPS agreements in D.04-06-014 and D.07-02-011 as modified by D.07-05-057³⁰. Standard Terms and Conditions (STC) identified in confidential Appendix B of that decision as "may not be modified".

"May Not be Modified" Terms

The PPA does not deviate from the non-modifiable terms and conditions except for non-substantive changes. See confidential Appendix C for a detailed comparison of each term that has been modified from its form in D.04-06-014 and/or subsequent decisions adopting STCs for use in PG&E's 2006 RPS solicitation.

"May be Modified" Terms

During the course of negotiations, the parties identified a need to modify some of the modifiable standard terms in order to reach agreement. These terms had all been designated as subject to modification upon request of the bidder in Appendix A of D.04-06-014. See confidential Appendix C for a detailed description and comparison of each term that has been materially modified from its form in D.04-06-014 and/or subsequent decisions adopting STCs for use in PG&E's 2006 RPS solicitation.

Contract Price is Reasonable

The levelized contract price does not exceed the 2006 MPR³¹ and therefore, the PPA is considered per se reasonable as measured according to the net present value calculations explained in D.04-06-015, D.04-07-029, and D.05-12-042. The net present value of the sum of payments to be made under the Agreements is less than the net present value of payments that would be made at the market price referent for the anticipated delivery. Confidential Appendix D demonstrates that the levelized contract payments, which have been adjusted for the appropriate project on-line date, are below the 2006 MPR, therefore, no supplemental energy payments are necessary for the proposed PPA.

Qualitative factors were considered during bid evaluation

PG&E considered qualitative factors as required by D.04-07-029 and D.06-05-039, i.e. credit and finance, project status, technology viability and participant experience, and consistency with RPS goals. PPM energy is an experienced developer of wind projects and is currently operating two facilities in the same resource area as the project proposed in AL 3090-E. Lastly, Klondike was advanced in its project development phase, demonstrating project viability.

The CPUC has adopted minimum quotas of RPS contracting from long-term contract or contracts with new facilities

Pub. Util. Code 399.14(b)(2) states that before the Commission can approve an RPS contract of less than ten years' duration, the Commission must establish "for each retail seller, minimum quantities of eligible renewable energy resources to be procured either through contracts of at least 10 years' duration or from new facilities commencing commercial operations on or after January 1, 2005." On May 3, 2007, the Commission approved D.07-05-028³² which established a minimum percentage of the prior year's retail sales that must be contracted with contracts of at least 10 years' duration or from new facilities commencing commercial operations on or after January 1, 2005. Predicated on PG&E meeting its minimum quota, deliveries from this contract will contribute to PG&E's obligation pursuant to D.07-05-028.

PPA is a viable project

PG&E believes the project is viable because:

Project Milestones

The PPA identifies the agreed upon commercial operation date as a guaranteed project milestones. Klondike notified PG&E that it has met all its project milestones and expects to achieve commercial operation prior to the guaranteed commercial operation date.

Financeability of resource

Klondike has received all necessary financing for the project and will become fully operational on or before the guaranteed commercial operation date.

Sponsor's creditworthiness and experience

PPM Energy, a subsidiary of Iberdrola, is an experienced wind developer.

Technology

Wind is a proven resource and Sherman County, Oregon is a known wind resource area. The Project site is located adjacent to existing wind facilities with a history of delivering wind generation.

Production Tax Credit (PTC)

Klondike is eligible for the federal PTC currently set to expire on December 31, 2008. The Seller has a no-fault termination right if the federal PTC is not extended as provided in Section 45 of the Internal Revenue Code of 1986, as amended. Given the near term Commercial Online Date, PTC risk is minimal.

The PPA and associated Shaping and Firming Agreement comply with EPS

Pursuant to SB 1368, D.07-01-039 adopted an interim Greenhouse Gas Emissions Performance Standard (EPS) for new long-term financial commitments by all LSEs. D.07-01-039 defined the conditions under which long-term baseload contracts for renewable energy, that are shaped and firmed energy with non-renewable energy sources, may be deemed EPS-compliant. For specified contracts with intermittent renewable resources [such as Klondike], "the amount of substitute energy purchases from unspecified resources is limited such that total purchases under the contract (whether from the intermittent renewable resource or from substitute unspecified sources) do not exceed the total expected output of the specified renewable powerplant over the term of the contract."³³

The Decision also states the Commission's expectations for an LSE to demonstrate compliance with the EPS and the condition stated above. Specifically, D.07-0-039 states: ³⁴

The burden is on the LSE to provide sufficient documentation in compliance submittals to demonstrate that the above requirements are met. In particular, the LSE is required to make available to Commission staff the source data and methodology it uses in developing the level of expected output from renewable resources under contracts with a term of five years or longer that permit substitute energy purchases from unspecified resources, in order to demonstrate that the limits for substitute energy purchases for both intermittent and dispatchable renewable resources were properly established under the substitute energy provisions.

To verify the expected output from the facility, PPM provided PG&E with seven years of meteorological data (met data) recorded from meteorological towers around the Klondike site. Meteorological towers record the information required to project a wind resource areas generation potential, such as, wind speed, wind direction, air temperature and barometric pressure.³⁵ Staff reviewed Klondike's hourly generation forecast submitted with AL 3090-E and also calculated the approximate capacity factor based on the MW capacity and estimated annual deliveries, and finds the projection reasonable. Specifically, we believe that it is reasonable to expect a new wind facility in this proven wind resource area to operate at an average capacity factor of approximately 30 percent.³⁶

The shaping and firming agreement includes terms and conditions to prevent PPM from delivering a greater quantity of system energy than is expected to be generated at Klondike. For each month of the contract term, PPM will provide PG&E a monthly schedule of projected generation. This monthly schedule can be structured to reflect significant deviations in projected wind generation and actual wind generation for the prior month. For example, if in the month of July wind generation is 25 percent less than was projected and therefore resulting in an excess of system energy to be delivered, then August's delivery schedule would be reduced by 25 percent to balance the aggregated deliveries. PPM is obligated to meet annual delivery requirements throughout the contract term to ensure the ratio of system energy delivered to COB does not exceed the ratio of green energy. PPM will incur financial penalties if these delivery requirements are not met.

TURN's protest is rejected without prejudice

On August 9, 2007, The Utility Reform Network (TURN) filed a protest against PG&E's AL 3090-E on the grounds that PG&E failed to demonstrate how the proposed project will comply with the Emissions Performance Standard (EPS) pursuant to SB 1368 and D.07-01-039. Specifically, TURN stated that nothing in the Advice Letter guarantees PG&E's "Firming Agreement" with PPM Energy is solely for "unspecific, system power." TURN asserts that it is unclear whether there is a loophole in the contract that would allow PPM to firm Klondike's wind power with specified sources that emit levels of greenhouse gases exceeding EPS rates.

We considered TURN's protest from information disclosed in the confidential terms and conditions of the PPA and associated shaping and firming agreement and find that the Agreements comply with EPS, the detail of which we discuss below.

The shaping and firming agreement in the Klondike PPA defines Shaped Energy in a manner that prevents PPM from executing a long-term contract for specific resources, that may exceed CPUC adopted EPS rates.³⁷

"Shaped Energy" means the Storage Energy of the Project as shaped and delivered by PPM to PG&E at the COB Delivery Point (as measured in MWhs) pursuant to the Firm Monthly Schedules and the terms of this Agreement as firm power consistent with the definition of firm power under Western Systems Power Pool Schedule C or any successor industry standard describing a substantially comparable energy product, except as more specifically defined and on the terms provided herein,³⁸

We consider "firm power consistent with the definition of firm power under Western Systems Power Pool Schedule C" to be analogous to energy from "unspecified" resources³⁹ or "system energy", and therefore in compliance with EPS requirements. Additionally, as PG&E stated in its response to TURN's protest, PPM is required to "tag" its system energy purchases used to firm the intermittent generation and this will verify the energy is purchased from "unspecified" resources. For these reasons, TURN's protest is rejected without prejudice.

We appreciate TURN's concern with upholding the intent of the EPS decision and encouraging the Commission to thoroughly review the first RPS contract for which the EPS rules must be applied. In order to facilitate public review of future contracts where the EPS is relevant, we request that PG&E disclose all information necessary to consider how the contract complies with D.07-01-039.

Clarification of Commission policy regarding stranded costs and disposition of protest

The Merced Irrigation District and Modesto Irrigation District (The Districts) filed a joint protest against PG&E's request for stranded cost recovery through a Commission resolution approving AL 3090-E. There is confusion among some parties regarding the relationship of renewable contracts, stranded costs, stranded cost recovery rules adopted in D.04-12-048, and the scope of Track 3 in R.06-02-013. In this resolution, we will clarify our policy.

The Districts have protested PG&E's "broad request for approval of stranded costs" in several of PG&E's advice letters because the Commission is currently considering stranded cost recovery issues in R. 06-02-013, and should not prejudge such issues in advice letters. The Districts state in the instant protest that, "...recovery of any stranded costs that may arise from the PPAs is subject to any Commission determination(s) in Rulemaking 06-02-013 (or any other proceeding) regarding implementation of the cost recovery provisions of D.04-12-048." ⁴⁰

The Districts' statement is consistent with recent Commission-approved resolutions. For example, in Resolution E-4110, approved September 6, 2007, the Commission stated in Conclusions of Law 8, "PG&E's request to recover payments for stranded costs or above-market costs associated with these contracts should be addressed in R.06-02-013" and in Ordering Paragraph 3, "To the extent that PG&E requests the recovery from its customers of stranded costs or above-market costs associated with these contracts, that request will be addressed in R.06-02-013."

PG&E, in its advice letters, requests cost recovery pursuant to D.04-12-048 for stranded costs associated with the particular contract submitted for Commission approval. In response to the District's protest of PG&E's request to recover above-market costs of the PPAs, PG&E references D.04-12-048, Conclusion of Law 16, "Stranded costs arising from RPS procurement activities should be collected from all customers, including departing load, over the life of the contract." PG&E makes the distinction in its response that D.04-12-048 determined that stranded costs from RPS contracts are eligible for cost recovery; however, the cost recovery mechanism is under consideration in R.06-02-013.

In effect, both parties are correct. We clarify our intent. When we approved individual contracts by resolution, we made no determination whether any stranded costs would in fact be incurred during the life of these contracts. As a result, in these resolutions, we declined to approve the recovery of stranded costs in connection with these contracts. Instead, we deferred this issue to R. 06-02-013 where the Commission could consider, if in fact stranded costs arise from a particular contract, the methodology to determine such "costs", the methodology of assigning those "costs", and other associated implementation details. Our intent was to make clear that we were not prejudging, in this or any other Resolution, whether the particular contract in question would result in stranded costs. We were not, and do not, in any way change or modify the Commission's ruling in D.04-12-048, as referenced above. In addition, we were not prescribing the manner in which stranded costs are determined or the potential impacts of implementation details, as R.06-02-013 is the appropriate proceeding for addressing these issues.

In light of the above, we clarify the following: by this Resolution we make no determination of whether stranded costs will in fact be incurred during the life of this contract. However, to the extent that such costs should occur, such costs will be eligible for stranded cost recovery subject to any determination in R.06-02-013 or any other proceeding regarding the implementation of cost recovery provisions of D.04-12-048. Although styled as a protest, we consider the Districts' position as a restatement of existing Commission policy. We therefore dispose of this "protest" through our further clarification of Commission policy.

PG&E's request for rate recovery of its transmission costs is not addressed in this resolution.

PG&E requests that the Commission make a finding related to undefined transmission costs, specifically requesting that the Commission:⁴¹

Finds that any cost of bringing generation from the delivery point to PG&E's load center shall be fully recoverable in rates over the life of the Agreements.

PG&E makes its request without providing sufficient information and/or citing relevant Commission Decisions. Moreover, the issue of cost recovery should be addressed using the appropriate process provided by the Commission, and not by resolution.

Confidential information about the contracts should remain confidential

Certain contract details were filed by PG&E under confidential seal. Energy Division recommends that certain material filed under seal pursuant to Public Utilities (Pub. Util.) Code Section 583 and General Order (G.O.) 66-C, and considered for possible disclosure, should be kept confidential to ensure that market sensitive data does not influence the behavior of bidders in future RPS solicitations.

COMMENTS

Public Utilities Code section 311(g)(1) provides that this resolution must be served on all parties and subject to at least 30 days public review and comment prior to a vote of the Commission. Section 311(g)(2) provides that this 30-day period may be reduced or waived upon the stipulation of all parties in the proceeding.

The 30-day comment period for this resolution has been reduced in accordance with the provisions of Rule 14.6 (c)(9). Rule 14.6 (c)(9) provides that the Commission may waive or reduce the comment period for a decision when the Commission determines that public necessity requires reduction or waiver of the 30-day period for public review and comment.  For purposes of Rule 14.6 (c)(9), "public necessity" refers to circumstances in which the public interest in the Commission's adopting a decision before expiration of the 30-day review and comment period clearly outweighs the public interest in having the full 30-day period for review and comment, and includes circumstances where failure to adopt a decision before expiration of the 30-day review and comment period would cause significant harm to public health or welfare. 

The public necessity in this case is that the renewable facility associated with Advice Letter 3090-E has an opportunity to achieve commercial operation prior to its original expected commercial online date. Shortening the comment period for the draft resolution will enable PG&E to receive renewable energy deliveries at the nearest opportunity and ensure that the RPS program move successfully towards the 20% by 2010 goal, and therefore, clearly serves the public interest. Any harm caused by shortening the comment period by four days is de minimis compared to the benefits of allowing parties immediate review of the draft resolution.

This matter will be placed on the first Commission's agenda 24 days following the mailing of this draft resolution. Comments shall be filed no later than 15 days following the mailing of this draft resolution, reply comments shall be filed no later than 20 days following the mailing of this draft resolution.

FINDINGS OF FACT

1. The RPS Program requires each utility, including PG&E, to increase the amount of renewable energy in its portfolio to 20 percent by 2010, increasing by a minimum of one percent per year.

2. D.04-06-014 set forth standard terms and conditions to be incorporated into RPS Power Purchase Agreements.

3. The California Energy Commission is responsible for certifying the RPS-eligibility of renewable facilities that are located out-of-state and have their firs point of interconnection to the WECC transmission system.

4. The California Energy Commission is responsible for verifying delivery from out-of-state facilities.

5. D.07-01-039, which adopted an interim Greenhouse Gas Emissions Performance Standard for contracts greater than 5 years in length, included compliance guidelines for when generation from intermittent renewable resources is firmed with energy from unspecified resources.

6. PG&E filed Advice Letter 3090-E on July 20, 2007, requesting Commission review and approval of a new renewable energy contract with PPM Klondike III Wind Power LLC and an associated shaping and firming agreement with PPM Energy, Inc.

7. PG&E filed Supplemental Advice Letter 3090-E-A on August 10, 2007, to submit its 2006 RPS Solicitation Independent Evaluator's report associated with the contract submitted for approval in Advice Letter 3090-E.

8. A protest to AL 3090-E was filed by The Utility Reform Network, and Merced Irrigation District and Modesto Irrigation District on August 9, 2007.

9. PG&E responded to the protests on August 16, 2007.

10. The protest by Merced Irrigation District and Modesto Irrigation District is disposed of through further clarification of Commission policy.

11. The protest by The Utility Reform Network is rejected without prejudice.

12. PG&E's request to recover payments for stranded costs or above-market costs associated with these contracts is not appropriate to address by resolution and should be addressed in R.06-02-013.

13. PG&E's request concerning the costs of bringing generation from the delivery point to PG&E's load center is not appropriate to address by resolution.

14. D.06-05-039 directed the utilities to issue their 2006 renewable RFOs, consistent with their renewable procurement plans.

15. The Commission required each utility to establish a Procurement Review Group (PRG) to review the utilities' interim procurement needs and strategy, proposed procurement process, and selected contracts.

16. PG&E briefed its Procurement Review Group regarding this contract on December 14, 2006, January 26, 2007, March 30, 2007, and May 30, 2007.

17. D.07-05-028 established conditions for counting deliveries from contracts of less than 10 years' duration for RPS compliance.

18. The proposed all-in contract price is below the 2006 MPR released in Resolution E-4049.

19. The Commission has reviewed the proposed PPA and associated shaping and firming agreement and finds them to be consistent with PG&E's approved 2006 renewable procurement plan.

CONCLUSIONS OF LAW

1. The RPS Program requires each utility, including PG&E, to increase the amount of renewable energy in its portfolio to 20 percent by 2010, increasing by a minimum of one percent per year.

2. The Commission requires each utility to establish a Procurement Review Group (PRG) to review the utilities' interim procurement needs and strategy, proposed procurement process, and selected contracts.

3. D.04-06-014 set forth standard terms and conditions to be incorporated into RPS PPAs.

4. The Commission has reviewed the proposed contract and finds it to be consistent with PG&E's approved 2006 renewable procurement plan.

5. These Agreements are reasonable and should be approved.

6. The California Energy Commission is responsible for certifying the RPS-eligibility of renewable facilities that are located out-of-state and have their first point of interconnection to the WECC transmission system.

7. The California Energy Commission is responsible for verifying delivery from out-of-state facilities.

8. D.07-01-039, which adopted an interim Greenhouse Gas Emissions Performance Standard for contracts greater than 5 years in length, included compliance guidelines for when generation from intermittent renewable resources is firmed with energy from unspecified resources.

9. Levelized contract price below the 2006 MPR is considered per se reasonable as measured according to the net present value calculations explained in D.04-06-015, D.04-07-029, and D.05-12-048.

10. The costs of the contract between PG&E and Seller are reasonable and in the public interest; accordingly, the payments to be made by PG&E are fully recoverable in rates over the life of the project, subject to CPUC review of PG&E's administration of the contract.

11. PG&E's request to recover payments for stranded costs or above-market costs associated with these contracts should be addressed in R.06-02-013.

12. PG&E's request concerning the costs of bringing generation from the delivery point to PG&E's load center should be addressed using the appropriate process provided by the Commission and not by resolution.

13. Certain material filed under seal pursuant to Public Utilities (Pub. Util.) Code Section 583 and General Order (G.O.) 66-C, and considered for possible disclosure, should not be disclosed. Accordingly, the confidential appendices, marked "[REDACTED]" in the redacted copy, should not be made public upon Commission approval of this resolution.

14. Procurement pursuant to this Agreement is procurement from an eligible renewable energy resource for purposes of determining Buyer's compliance with any obligation that it may have to procure eligible renewable energy resources pursuant to the California Renewables Portfolio Standard (Public Utilities Code Section 399.11 et seq.), Decision 03-06-071, or other applicable law.

15. Procurement pursuant to this Agreement constitutes incremental procurement or procurement for baseline replenishment by Buyer from an eligible renewable energy resource for purposes of determining Buyer's compliance with any obligation to increase its total procurement of eligible renewable energy resources that it may have pursuant to the California Renewables Portfolio Standard, CPUC Decision 03-06-071, or other applicable law;

16. Any indirect costs of renewables procurement identified in Section 399.15(a)(2) shall be recovered in rates;

17. AL 3090-E and Supplemental AL 3090-E-A should be approved.

THEREFORE IT IS ORDERED THAT:

1. AL 3090-E and Supplemental AL 3090-E-A are approved.

2. The costs of the contract between PG&E and Seller is reasonable and in the public interest; accordingly, the payments to be made by PG&E, at or below the MPR, are fully recoverable in rates over the life of the project, subject to CPUC review of PG&E's administration of the contract.

3. To the extent that PG&E requests the recovery from its customers of stranded costs or above-market costs associated with these contracts, that request will be addressed in R.06-02-013.

4. This Resolution is effective today.

I certify that the foregoing resolution was duly introduced, passed and adopted at a conference of the Public Utilities Commission of the State of California held on November 16, 2007; the following Commissioners voting favorably thereon:

_______________

PAUL CLANON

Executive Director

Appendix A

CEC Pre-Certification of Out-of-State Delivery

Attachment A

Appendix B

CEC RPS-Eligibility Guidelines for Out-of-State Generation

D. Eligibility of Out-of-State Facilities⁴²

This section applies to renewable facilities that are located out-of-state and have their first point of interconnection to the WECC transmission system outside the state, as defined in the Overall Program Guidebook. Facilities that have their first point of interconnection to the WECC transmission system within the state are considered to be in-state facilities and are not subject to the requirements of this section for purposes of RPS or SEP eligibility. Out-of-state facilities that are not or will not be interconnected to the WECC transmission system are not eligible for the RPS.

Note that the delivery requirements described here for out-of-state facilities do not apply to electric corporations that serve retail end-use customers outside California and have 60,000 or fewer customer accounts in California under Public Utilities Code Section 399.17. Section 399.17 modifies the definition of an eligible renewable energy resource to include out-of-state facilities for certain electric corporations, such as PacifiCorp and Sierra Pacific Power, which serve customers both in and outside California.

Generation from renewable facilities located out-of-state is potentially eligible for both the RPS and SEPs. To qualify for the RPS or SEPs, generation from an out-of-state facility must meet the RPS eligibility requirements described above and must satisfy all of the following criteria.

a) Is located so that it is or will be connected to the WECC transmission system.

b) Commences initial commercial operations on or after January 1, 2005, (except in the case of small hydroelectric and conduit hydroelectric facilities, which must commence initial commercial operations on or after January 1, 2006, and January 1, 2007, respectively, to qualify for SEP eligibility).

c) Demonstrates delivery of its generation to an in-state market hub or in-state location, as specified in the delivery requirements below.

d) Does not cause or contribute to any violation of a California environmental quality standard or requirement.

e) If located outside the United States, it is developed and operated in a manner that is as protective of the environment as a similar facility located in California.

f) Participates in an RPS tracking and verification system approved by the Energy Commission.

g) Satisfies the "Delivery Requirements" set forth below.

If the facility meets all of the above criteria except it commenced commercial operations before January 1, 2005 (criterion "b" above), then it may be RPS-eligible (but not SEP-eligible) if it meets one of the following two criteria:

a) The electricity is from incremental generation resulting from project expansion or repowering of the facility, or

b) b) The facility is part of a retail seller's existing baseline procurement portfolio as identified by the CPUC.

For retail sellers that serve end-use customers outside California and have 60,000 or fewer customer accounts in California under Public Utilities Code Section 399.17, such as PacifiCorp and Sierra Pacific Power, electricity procured from a facility located out-of-state must, in lieu of the foregoing criteria, meet the following criteria to be eligible for the RPS:

a) The generation must be procured by the retail seller on behalf of its California customers and is not used to fulfill its renewable energy procurement requirements in other states or any other renewable energy retail claim.

b) b) The facility is connected to the WECC.

c) c) The facility and retail seller must participate in an RPS tracking and verification system approved by the Energy Commission.

Generation procured by retail sellers under Public Utilities Code Section 399.17 is not eligible for SEPs.

E. Delivery Requirements

For purposes of RPS compliance, electricity is deemed delivered if it is either generated at a location within the state or is scheduled for consumption by California end-use retail customers as specified in Public Resources Code Section 25741, Subdivision (a). Consequently, electricity generated by facilities located in-state or having their first point

of interconnection to the WECC transmission system in-state satisfies California RPS delivery requirements.

To count generation from out-of-state facilities for purposes of RPS compliance, the facility must enter a power purchase agreement with the retail seller or procurement entity and electricity must be delivered to an in-state market hub (also referred to as "zone") or in-state point of delivery (also referred to as "node") located within California. The retail seller or procurement entity and Seller may negotiate which party is responsible for securing transmission at any point along the delivery path as long as the energy is delivered into California. The retail seller or procurement entity may document delivery from a control area operator (also referred to as "balancing authority") in the WECC transmission system. The Energy Commission will compare the amount of RPS-eligible energy generated by the RPS-eligible facility per calendar year with the amount of energy delivered into California for the same calendar year and the lesser of the two amounts may be counted as RPS-eligible procurement (for more discussion see "verification of delivery"). The generation from the facility must be under a power purchase agreement with the retail seller or procurement entity. The delivery must be made consistent with North American Electric Reliability Corporation (NERC) rules and documented with a NERC tag as described below.

The following deliverability requirements were developed in consultation with the California ISO. These requirements must be satisfied for an out-of-state facility to qualify for the RPS or SEPs (with the exception noted above for retail sellers subject to Public Utilities Code Section 399.17). The delivery requirements do not apply to facilities located outside of California whose first point of interconnection to the WECC transmission system is located in California.

1. The retail seller, procurement entity, or facility representative must either (a) arrange for an interchange transaction with the California ISO to deliver the facility's energy to a point of delivery in California, or (b) arrange for an interchange transaction with another balancing authority to deliver energy to the point of delivery in California. In accordance with the policies of the NERC, the interchange transaction must be tagged as what is commonly referred to as a "NERC tag," which requires, among other things, that information be provided identifying the Generation Providing Entity, the "Source" or "Point of Receipt," the physical transmission path for delivery showing intermediary "Points of Delivery," the contract or market path, the final Point of Delivery or load center known as the "sink," and the Load Serving Entity responsible for the consumption of electricity delivered.

2. The Source identified on the NERC tag may be a specific RPS-eligible facility registered as a unique source or may be any balancing authority located in the WECC.

3. The RPS certification number of the facility or facilities (or RPS pre-certification number, in the case of local publicly-owned electric utilities) that is/are engaged in a power purchase agreement with a retail seller or procurement entity (or local publicly-owned electric utility implementing these delivery requirements as part of compliance with its RPS) must be shown on the comment field of the NERC tag.

4. The facility must provide the Energy Commission with its NERC identification (Source point name)10 if it registers as a unique source, or the Source point name of its balancing authority when it applies for RPS certification.

5. The facility representative, retail seller, or procurement entity (or local publicly-owned electric utility implementing these delivery requirements as part of compliance with its RPS) must request and receive acceptance of a NERC tag between a balancing authority in California and a balancing authority in WECC.

6. The applicable parties (the Generation Providing Entity and Load Service Entities) must agree to make available upon request documentation of the NERC tag to the Energy Commission. On May 1 of each year (or the next business day), the retail seller or procurement entity must submit an annual report documenting compliance with this NERC tag requirement for the previous calendar year to the Energy Commission.

7. The facility must submit verification of its generation to the Energy Commission annually. Please refer to the section on the "Generation Tracking System." The Energy Commission will use these data to verify the actual generation of power that was scheduled for delivery via NERC tags.

8. If a facility has obtained a SEP award, the Energy Commission will verify that SEPs were granted only for generation that satisfies delivery requirements. For more information, please refer to the New Renewable Facilities Program Guidebook.

Confidential Appendix C

Contract Summary

Confidential Appendix D

MPR - SEP Worksheet

Confidential Appendix E

Overview of 2004-2006 Solicitation Bids

Confidential Appendix F

Least-Cost Best-Fit Evaluation

Confidential Appendix G

Contribution to RPS Goal

ARNOLD SCHWARZENEGGER, Governor

PUBLIC UTILITIES COMMISSION

505 VAN NESS AVENUE

SAN FRANCISCO, CA 94102-3298

I.D. #7088

October 23, 2007 Draft Resolution E-4128

November 16 Commission Meeting

TO: PARTIES TO DRAFT RESOLUTION E-4128

Enclosed is draft Resolution E-4128 of the Energy Division addressing PG&E's advice letter 3090-E. It will be on the agenda at the November 16, 2007 Commission meeting. The Commission may then vote on this Resolution or it may postpone a vote until later.

When the Commission votes on a draft Resolution, it may adopt all or part of it as written, amend, modify or set it aside and prepare a different Resolution. Only when the Commission acts does the Resolution become binding on the parties.

Parties may submit comments on the draft Resolution no later than Wednesday, November 7, 2007.

An original and two copies of the comments, with a certificate of service, should be submitted to:

Honesto Gatchalian

Energy Division

California Public Utilities Commission

505 Van Ness Avenue

San Francisco, CA 94102

fax: 415-703-2200

email: jnj@cpuc.ca.gov

An electronic copy of the comments should be submitted to:

Sean Simon

Energy Division

svn@cpuc.ca.gov

Those submitting comments and reply comments must serve a copy of their comments on 1) the entire service list attached to the draft Resolution, 2) all Commissioners, and 3) the Director of the Energy Division.

Comments may be submitted electronically.

Comments shall be limited to five pages in length plus a subject index listing the recommended changes to the draft Resolution, a table of authorities and an appendix setting forth the proposed findings and ordering paragraphs.

Comments shall focus on factual, legal or technical errors in the proposed draft Resolution. Comments that merely reargue positions taken in the advice letter or protests will be accorded no weight and are not to be submitted.

Reply comments shall be served on parties and Energy Division no later than Monday, November 12, 2007, and may also be submitted electronically.

Late submitted comments or reply comments will not be considered.

Paul Douglas

Project and Program Supervisor

Energy Division

Service List: R.06-05-027, R01-10-024

¹ On October 14, 2007, the Governor signed SB 1036 which transfers the authority to approve above market costs from the California Energy Commission to California Public Utilities Commission. http://www.leginfo.ca.gov/cgi-bin/postquery?bill_number=sb_1036&sess=0708&house=B

² Chapter 516, statutes of 2002, effective January 1, 2003 (SB 1078)

³ The Energy Action Plan was jointly adopted by the Commission, the California Energy Resources Conservation and Development Commission (CEC) and the California Power Authority (CPA). The Commission adopted the EAP on May 8, 2003.

⁴ http://www.cpuc.ca.gov/Published/Final_decision/36206.htm

⁵ APT - An LSE's APT for a given year is the amount of renewable generation an LSE must procure in order to meet the statutory requirement that it increase its total eligible renewable procurement by at least 1% of retail sales per year.

⁶ Chapter 464, Statutes of 2006 (SB 107)

⁷ Pub. Util. Code Section 399.14(a)(2)(C)

⁸ D.04-07-015

⁹ http://www.cpuc.ca.gov/word_pdf/FINAL_DECISION/52178.pdf

¹⁰ Respectively, Resolution E-3980: http://www.cpuc.ca.gov/WORD_PDF/FINAL_RESOLUTION/55465.DOC, Resolution E-4049: http://www.cpuc.ca.gov/word_pdf/FINAL_RESOLUTION/63132.doc, Resolution E-4110: http://www.cpuc.ca.gov/word_pdf/FINAL_RESOLUTION/73594.pdf

¹¹ D.06-10-050, Attachment A, http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/61025.PDF) as modified by D.07-03-046 ( http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/65833.PDF.

¹² The IPT represents the amount of RPS-eligible procurement that the LSE must purchase, in a given year, over and above the total amount the LSE was required to procure in the prior year. An LSE's IPT equals at least 1% of the previous year's total retail electrical sales, including power sold to a utility's customers from its DWR contracts.

¹³ http://www.energy.ca.gov/2007publications/CEC-300-2007-006/CEC-300-2007-006-CMF.PDF

¹⁴ Chapter 464, Statutes of 2006 (SB 1368)

¹⁵ D.07-01-039 adopted an emission rate of 1,100 pounds of carbon dioxide per megawatt-hour for the proxy CCGT (section 1.2, page 8) http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/64072.PDF

¹⁶ "Baseload generation" is electricity generation at a power plant "designed and intended to provide electricity at an annualized plant capacity factor of at least 60%." § 8340 (a)

¹⁷ D.07-01-039, Conclusion of Law 40. Note: These compliance rules specifically apply to IOUs, additional compliance rules may apply to other RPS-obligated load serving entities.

¹⁸ California Pub. Util. Code section 399.11 et seq., as interpreted by D.03-07-061, the "Order Initiating Implementation of the Senate Bill 1078 Renewables Portfolio Standard Program", and subsequent CPUC decisions in Rulemaking (R.) 04-04-026, R.06-02-012 and R.06-05-027.

¹⁹ See PG&E's Renewables Portfolio Standard Periodic Compliance Report, page 18, August 1, 2007 (R.06-05-027).

²⁰ http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/43224.PDF

²¹ Pub. Util. Code, Section §399.14

²² Pub. Util. Code, Section §399.14(a)(3)

²³ On December 6, 2007, the three large IOUs were granted an extension by letter from the Executive Director (CPUC) on the date by which contracts eligible for earmarking in 2006 must be executed and submitted to the CPUC for approval.

²⁴ PG&E's 2006 Renewables Portfolio Standard Short List Report, December 22, 2006 (R.06-05-027).

²⁵ D.04-07-029

²⁶ D.04-12-048 (Findings of Fact 94-95, Ordering Paragraph 28) and D.06-05-039 (Finding of Fact 20, Conclusion of Law 3, Ordering Paragraph 8).

²⁷ Sedway Consulting, Inc. served as independent evaluator for PG&E's 2006 RPS Solicitation.

²⁸ PG&E's RPS Renewable Energy Procurement Plan, June 30, 2006, section XI, page (p.) 34-35.

²⁹ PG&E's 2006 Transmission Ranking Cost Report, filed March 15, 2006

³⁰ Order Modifying Decision 07-02-011 Regarding Definition of Green Attributes http://www.cpuc.ca.gov/word_pdf/FINAL_DECISION/68383.pdf

³¹ 2006 MPR Resolution E-4049 http://www.cpuc.ca.gov/word_pdf/FINAL_RESOLUTION/63132.pdf

³² http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/67490.PDF

³³ D.07-01-039, COL #40

³⁴ D.07-01-039, page 151

³⁵ http://www.caiso.com/1bad/1bade8443eb80.pdf

³⁶ A 2004 Black&Veatch study reported California's average installed wind capacity factor to be 26.6 percent. http://www.regie-energie.qc.ca/audiences/3526-04/MemoiresParticip3526/Memoire_CCVK_33_BV_int_renew2.pdf

³⁷ PG&E and PPM agreed to provide this information, and do so without waiving their right to maintain the confidentiality of the PPM Agreement pursuant to D.06-06-066 and other Commission rules or orders.

³⁸ "Storage Energy" is used to define the amount of renewable energy generated by Klondike, and delivered from PG&E to PPM Energy.

³⁹ Throughout D.07-01-039, "unspecified" resources is sometimes referred to as "system power" or "system energy".

⁴⁰ Merced Irrigation District and Modesto Irrigation District protest to Advice 3090-E, filed August 9, 2007.

⁴¹ Advice Letter 3090-E, July 20, 2007, page 12

⁴² http://www.energy.ca.gov/2007publications/CEC-300-2007-006/CEC-300-2007-006-CMF.PDF