MAILED 12/21/07

PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

ENERGY DIVISION RESOLUTION E-4138

December 20, 2007

REDACTED

RESOLUTION

Resolution E-4138. Pacific Gas and Electric (PG&E) Company requests approval of a renewable resource procurement contract resulting from its 2005 RPS solicitation. The contract is approved without modification.

By Advice Letter 3092-E filed on July 25, 2007 and Supplemental Advice Letter 3092-E-A filed on November 30, 2007.

__________________________________________________________

SUMMARY

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

PG&E's renewable contract complies with the Renewable Portfolio Standard (RPS) procurement guidelines and is approved. PG&E's request for approval of the renewable resource procurement contract is granted pursuant to D.05-07-039. The energy acquired from the contract will count towards PG&E's Renewable Portfolio Standard (RPS) requirements.

Deliveries from the contract are reasonably priced and fully recoverable in rates over the life of the contract; subject to Commission review of PG&E's administration of the contract.

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

Process for above-market cost recovery has been reformed

Pursuant to SB 1078 and SB 107, the California Energy Commission (CEC) was authorized to "allocate and award supplemental energy payments" to cover above-market costs¹³ of long-term RPS-eligible contracts executed through a competitive solicitation.¹⁴ The CEC required that developers seeking above-market costs apply to the CEC for supplemental energy payments (SEPs); however, the legislature determined that it was inefficient for developers to apply to the CEC for above-market costs while the CPUC reviewed RPS contracts for approval. Additionally, SEPs proved difficult to finance and therefore, SEPs became an impediment to project viability.

Consequently, on October 14, 2007, Governor Schwarzenegger signed SB 1036,¹⁵ which authorizes the CPUC to provide above-market cost recovery through rates. The legislative intent of SB 1036 was to limit the RPS procurement costs above the MPR, beyond which the utilities cannot be required to procure. The cost limitation is equal to the amount of funds currently accrued in the CEC's New Renewable Resources Account, and the portion of funds which would have been collected through January 1, 2012. The CEC is required to refund existing funds to the three large IOUs by March 1, 2008, and terminate the New Renewable Resources Account from Public Resources Code Section § 25751 by July 1, 2008.¹⁶ Once implemented, it is expected that SB 1036 will further streamline RPS contract approval and facilitate financing for projects with above-market costs.

Pursuant to SB 1036, Pub. Util. Code § 399.15(d)(2) provides that:

The above-market costs of a contract selected by an electrical corporation may be counted toward the cost limitation if all of the following conditions are satisfied:

(A) The contract has been approved by the commission and was selected through a competitive solicitation pursuant to the requirements of subdivision(d) of Section 399.14.

(B) The contract covers a duration of no less than 10 years.

(C) The contracted project is a new or repowered facility commencing commercial operations on or after January 1, 2005.

(D) No purchases of renewable energy credits may be eligible for consideration as an above-market cost.

(E) The above-market costs of a contract do not include any indirect expenses including imbalance energy charges, sale of excess energy, decreased generation from existing resources, or transmission upgrades.

The CEC and CPUC are working collaboratively to implement SB 1036, which has an effective date of January 1, 2008. CEC Staff notified parties with active SEP applications that they should withdraw their applications and seek above-market cost recovery from the CPUC, consistent with SB 1036. Prior to the CPUC's full implementation of SB 1036, the Commission may approve contracts with above-market costs and cost recovery will be approved through rates. Pursuant to SB 1036, the approved costs above the MPR may be applied toward the cost limitation.

PG&E requests approval of a new renewable energy contract

On July 25, 2007, PG&E filed Advice Letter (AL) 3092-E requesting Commission approval of a renewable procurement contract with SOLEL-MSP-1, LLC (Solel). The power purchase agreement (PPA) results from PG&E's 2005 RPS solicitation which was authorized by D.05-07-039 on July 21, 2005.¹⁷ The Commission's approval of the PPA will authorize PG&E to accept future delivery of incremental renewable generation, which will contribute towards the 20 percent renewables procurement goal required by California's RPS statute.¹⁸

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 PPA in its entirety, finds that PG&E's execution of the PPA is reasonable and in the public interest, and finds that PG&E's payments to be made under the PPA are reasonable and fully recoverable in rates over the life of the contract, subject to CPUC review of PG&E's administration of the Agreement;

2. Finds that any procurement pursuant to this PPA 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 the proposed development and deliveries will not occur as described by the agreement 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, and that PG&E shall not be subject to penalties for RPS delivery shortfalls due to seller non-performance, consistent with previous decisions.

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

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 contract.

6. Finds that any stranded costs that may arise from these contracts 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 the progress of its 2005 RPS solicitation on five occasions. The first briefing occurred on September 30, 2005, and focused on the results of PG&E's August 4, 2005 solicitation. The second briefing was October 24, 2005 at which PG&E reviewed the results of the bid evaluation and provided its preliminary short-list. On December 1, 2005, PG&E reviewed the status of negotiations with short-listed bidders and responded to concerns raised at the previous presentation. At the January 12 and March 29, 2006 meetings, PG&E provided the PRG with an overview of the projects it considered most likely to proceed to final agreement. These presentations included a general overview of the negotiated terms and conditions of these and other PPAs. On May 3, June 15, and August 28, 2006, PG&E provided the PRG with a status report of the 2005 Solicitation and described and presented the Solel project in the context of the 2005 Solicitation results. On March 30 and May 30, 2007, PG&E updated the PRG on Solel and PG&E's overall "Solar Strategy".

PRG members expressed general satisfaction with the manner in which PG&E arrived at its 2005 RPS shortlist and the resulting PPAs. There was no opposition to PG&E's decision to execute the contract that is the subject of this Advice Letter. Although Energy Division is a member of the PRG, it reserved its conclusions for review and recommendation on the contracts to the resolution process.

NOTICE

Notice of AL 3092-E and Supplemental AL 3092-E-A was 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 AL 3092-E was timely protested by Merced Irrigation District and Modesto Irrigation District (Districts) on August 14, 2007. The Districts protested PG&E's advice letter on two issues. First, the Districts objected to PG&E's request for approval of stranded cost recovery in connection with the PPA. The Districts state that the issue regarding implementation of stranded cost recovery, pursuant to D.04-12-048,¹⁹ is presently being considered by the Commission. Secondly, the Districts object to PG&E's request that municipal departing load (MDL) pay for costs above the market price referent (MPR) portion of the contract. The Districts state that any proposal by PG&E to recover above-market costs and/or above-MPR costs from MDL should be rejected because MDL will not benefit from the contract, PG&E failed to comply with the least-cost imperative and because the Seller made no effort to obtain supplemental energy payments from the California Energy Commission.

On August 21, 2007, PG&E responded to the Districts protest. PG&E argues that the Districts' protest is based on misconceptions of the Commission's stranded cost recovery policy, the RPS Solicitation contract selection process, above-market costs in the RPS context, and the CEC's supplemental energy payment process. PG&E states that the Districts will benefit from the RPS project as a matter of State law, that is, even though actual deliveries will go to PG&E's customers, the Districts benefit from greater resource diversity for the State. Additionally, PG&E requests that the Commission find that any stranded costs associated with the Project are eligible for cost recovery, pursuant to Commission policy determined in D.04-12-048 and ongoing issues to be resolved in R.06-02-013.

DISCUSSION

Description of the project

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

Energy Division examined the contract on multiple grounds:

· PPA is consistent with PG&E's CPUC adopted 2005 RPS Plan and was executed through a competitive solicitation

· PG&E's Bid evaluation process is consistent with Least-Cost Best-Fit (LCBF) decision

· PPA conforms to CPUC adopted Standard Terms and Conditions

· PG&E made a sufficient showing the project is viable

· PG&E made a sufficient showing the project's contract price is reasonable

PPA is consistent with PG&E's CPUC adopted 2005 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.²⁰ PG&E's 2005 RPS procurement plan (Plan) was approved by D.05-07-039 on July 21, 2005.²¹ 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

PPA is consistent with identified resource needs

The stated goal of PG&E's 2005 RPS Solicitation Plan was to procure approximately 1-2 percent of PG&E's retail sales volume or between 700 and 1,400 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 dispatchable resources. If approved, the 554 MW facility is expected to deliver approximately twice PG&E's IPT, that is, two percent of PG&E's total retail sales.

PPA selection is consistent with RPS Solicitation Protocol

The PPA is consistent with the RPS plan because it was achieved through PG&E's adherence to its 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.

2. Using the approved bid solicitation protocol and forms of power purchase agreements, PG&E commenced its solicitation on August 4, 2005. Bids were received until September 15, 2005, 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.

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 24, 2005. 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 2 and May 3, 2006. On March 30, 2007 PG&E discussed its ongoing negotiations with Solel and the Project's role as part of PG&E's overall solar strategy; the PRG had no objection to PG&E proceeding to execute the PPA presented by this advice letter.

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

The LCBF decision²³ directs the utilities to use certain criteria in their bid ranking. It 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. PG&E included a description of its LCBF process with its proposed 2005 procurement plan and bid protocol; no parties protested the reasonableness of PG&E's methodology for evaluating non-affiliate bids.

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. A product's 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. 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, i.e., its proxy for firm system energy.

Portfolio Fit

Portfolio fit considers how well an offer variation'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 on-peak energy, the acceptance of these as-available deliveries should not result in significant remarketing costs.

The TRCR, for short-listing purposes only, assigns the additional costs associated with deliveries from a project, absent transmission upgrades. Solel was assigned SCE Cluster 6 in PG&E's 2006 TRCR. Based on this assignment and its as-available delivery profile, Solel was assigned a transmission cost adder of -$2.20/MWh to account for increased costs to deliver its generation to SP-15.

Transmission and Scheduling

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 2005 transmission ranking cost report (TRCR) ²⁴ 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 needed to accommodate delivery at this cluster, PG&E assigned a transmission adder to each Offer for evaluation.

The TRCR, for short-listing purposes only, assigns the additional costs associated with deliveries from a project, absent transmission upgrades. Solel was assigned SCE Cluster 6 in PG&E's 2006 TRCR. Based on this assignment and its as-available delivery profile, Solel was assigned a transmission cost adder of -$2.20/MWh to account for increased costs to deliver its generation to SP-15.

Since Solel's first point of interconnection is within the service territory of Southern California Edison Company (SCE), the transmission adder is calculated as the sum of the TRCR at the SCE cluster closest to Solel and PG&E's cluster closest to the interconnection point between PG&E and SCE (Midway). This cost was then compared to the cost of commercial alternatives to physically delivering the power to PG&E's load center, and the lower of the two costs was imputed to the cost of power from the proposed project. Because no constraints for on-peak deliveries from "south to north" were identified, the TRC adder of $2.20/MWh reflected an estimate of the cost of adding additional voltage support to the system.

Terms and conditions of delivery

Solel or its agent will serve as the Scheduling Coordinator (SC) for the Project throughout the Delivery Term. The SC is responsible for accurately scheduling its daily generation. The point of delivery will be within SP-15. Following the implementation of the California Independent System Operator's (CAISO) Market Redesign Technology Upgrade (MRTU), the Project's delivery points become their interconnection point with the CAISO grid.²⁵

Transmission upgrades

Because the CAISO transmission studies have not been completed, and the Seller has yet to finalize its Project site, the necessity and or extent of network upgrades is undetermined at this time. That said, the Parties negotiated terms and conditions that consider the total cost of necessary network upgrades and its impact on project viability; these provisions limit the potential financial risk to ratepayers. See confidential Appendix A for a detailed description of the PPA terms and conditions related to transmission upgrades.

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, D.07-02-011 as modified by D.07-05-057,²⁶ and D.07-11-025²⁷. Standard Terms and Conditions (STC) were identified in confidential Appendix B of D.04-06-014 as "may not be modified". On November 16, 2007, the Commission adopted D.07-11-025, which reduced the number of non-modifiable terms from nine to four, and refined the language of some of these terms in response to an amended petition for modification of D.04-06-014.²⁸ The remaining non-modifiable STCs include "CPUC Approval", "RECs and Green Attributes", "Eligibility" and "Applicable law". On November 30, 2007, PG&E filed Supplemental AL 3092-E-A, which brought the PPA into compliance with Attachment A of D.07-11-025.

"May Not be Modified" Terms

The PPA does not deviate from the non-modifiable terms and conditions.

"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 and in D.07-11-025.

PPA is a viable project

PG&E believes the project is viable because:

Project Milestones

The PPA identifies the agreed upon project milestones, including the construction start date and commercial operation date. The Seller's obligations to meet these milestones are supported by performance assurance securities. PG&E believes that the Seller's Project development plan allows all milestones to be achieved.

Financeability of resource

PG&E believes that the project selected has a reasonable likelihood of being financed and completed as required by the PPA and will be available to deliver energy by the guaranteed commercial operation date. Specifically, Solel's technology has a demonstrated production history and has recently realized efficiency gains, which should minimize financing risk. Furthermore, Solel has tripled its manufacturing capacity for its thermal receiving tubes and retained a significant portion of materials for its Project with PG&E.²⁹ See confidential Appendix A, "Project Viability" for confidential information about the Contract.

Sponsor's creditworthiness and experience

The 2005 bidders were required to provide credit-related information as part of their bid. PG&E has reviewed this information and is satisfied that the Seller possesses the necessary credit and experience to perform as required by the PPA. Solel's engineering and project development team benefit from twenty years of solar thermal research, product development and commercialization. Recent achievements include the utilization of Solel's proprietary technology at Acciona's Nevada One 64 MW solar thermal facility, which began commercial operation in March 2007.³⁰

Technology

Concentrating solar thermal is a proven technology. Solel will employ in essence, the same technology developed by Luz, the company which built approximately 350MW of concentrating solar thermal capacity in the Mojave Desert between 1984 and 1991.³¹ These original facilities are still operational.

Solel has increased the efficiency of its technology. In July, 2007, Solel sold 100 MW of its new receiver tubes to FPL, which has resulted in increased production at FPL's facilities, most notably on hazy days when generation would otherwise be poor. See confidential Appendix A, "Technology" for confidential information about the Project's technology.

Fuel Quality

This Project will be located in the Mohave Desert area of Southwestern California, which is recognized as one of the best solar sites in the world. The Solar Electric Generating Stations (SEGS) were developed in this region from 1984 to 1990 and have operated consistently and reliably for almost 20 years, generating approximately 350 MW of electricity. Solel has also been collecting radiation data on a regular basis from the SEGS facilities and from the Fort Mohave area near Needles, California; all three potential Project sites have similar climatic conditions which are suitable for the proposed Project.

Production Tax Credit (PTC)

The PPA is not contingent upon, nor is the pricing dependent on, the extension of the federal PTC as provided in Section 45 of the Internal Revenue Code of 1986, as amended.

Investment Tax Credit (ITC)

Solel is eligible for the 30% ITC. The Seller has a no-fault termination right that may be exercised if the ITC is not extended by December 31, 2007. See confidential Appendix A, for confidential information related to the ITC.

Contract Price is Reasonable

While the levelized contract price exceeds the 2005 MPR,³² Staff believes that the contract is reasonable. Specifically, the Project's contract price compares favorably to other concentrating solar thermal bids in the 2005, 2006 and 2007 RPS solicitations. Furthermore, Staff finds that the Contract discussed herein complies with the requirements for above-market cost recovery pursuant to SB 1036. Specifically, this Contract was selected through a competitive solicitation for long-term renewable energy deliveries from a new facility.

Approval of this Contract will increase in-state renewable energy generation and provide greater resource diversity. The price reasonableness evaluation discussed in this resolution does not set precedence for Commission review of RPS contracts. Confidential Appendix A includes a detailed discussion of the PPA's pricing terms. Confidential Appendix B demonstrates that the net present value of the sum of payments to be made under the PPA is greater than the net present value of payments that would be made at the market price referent for the anticipated delivery.

Energy Division Staff modified the 2005 Market Price Referent (MPR)

Background

In D.04-06-015³³, we adopted a methodology to calculate 10, 15, and 20 year MPR, for use in the 2004 renewable power solicitations, as generally set forth in Pub. Util. Code § 399.15. In addition, D.04-06-015 directed staff to prepare the MPR calculation and release it through a joint Assigned Commissioner and Administrative Law Judge (ALJ) ruling. Parties filed comments and reply comments on the staff report releasing the MPR calculation. Staff then prepared a resolution for the adoption of the final MPR for 2004.³⁴ D.04-06-015 also authorized an evaluation process for contracts that do "not conform" to standard MPR terms.

Decision 04-06-015, page 8-9

 "Finally, we need to address the possibility that not all bidders may be able to submit bids that conform to the 10-, 15-, or 20-year contract term.  A bidder may, for example, submit a 12-year contract bid.  The MPR methodology, and associated model, set forth in this decision can be modified to calculate MPRs for different contract terms.  If additional MPRs are required for bid evaluation, we authorize Energy Division to generate the necessary MPRs utilizing the same input values used to generate the 10-, 15-, or 20-year MPRs approved by this Commission.  Alternatively, we could calculate all intermediate MPRs between years 10 and 20.  When the utilities notify the Commission that negotiations with RPS bidders are complete, they should also indicate if the calculation of MPRs for terms other than 10, 15 or 20 years is necessary.

Calculation of 25-year MPR

PG&E executed a 25-year PPA with Solel; however, the MPR methodology only calculates values for 10, 15 and 20-year projects. In order to accurately calculate the above-market costs of the contract, Energy Division calculated a 25-year benchmark using the 2005 MPR model. Pub. Util. Code § 399.15, and D.04-06-014, give the Commission and Energy Division the authority to approve RPS contracts of essentially any term of years, so long as the Commission has established a way to evaluate them.

Resolution E-3980 formally adopted the 2005 MPR values for use in the 2005 RPS solicitation. The relevant 10, 15, and 20-year MPRs for projects executed in 2005, with a 2011 online date are the following; $76.49, $79.73, and $82.92/MWh, respectively. The percentage change between the 15-year and 20-year MPR is 4.0%. Applying that percentage increase to the 20-year MPR of $82.92 returns an approximate 25-year MPR of $86.24/MWh.

Qualitative factors were considered during bid evaluation

PG&E considered qualitative factors as required by D.04-07-029 and D.05-07-039, i.e. credit and finance, project status, technology viability and participant experience, and consistency with RPS goals. Solel's technology is the only commercialized concentrating solar technology and produces on-peak utility-scale generation. If approved, Solel will contribute to the diversification of PG&E's renewable technology portfolio and significantly increase PG&E's RPS procurement in 2011 and beyond.

Commission has adopted minimum quotas for long-term RPS contracting

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.07-05-028³⁵ 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. As a new, long-term Contract, deliveries from this Project will contribute to PG&E's minimum quota requirement.

Clarification of Commission policy regarding stranded costs and disposition of protest

Merced Irrigation District and Modesto Irrigation District (Districts) filed a joint protest against PG&E's request for stranded cost recovery through a Commission resolution approving AL 3092-E. This protest indicates that 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." ³⁶

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 PPA, PG&E references D.04-12-048, page 57:³⁷

In general we agree that the utilities should be allowed to recover their stranded costs from all customers, including a surcharge. Such an approach best meets the Commission's goals of providing "the need for reasonable certainty of rate recovery" (as required under AB 57 and noted in the June 4th ACR) as well as best ensuring that California meets its energy needs.

Requiring departing customers to assume a fair share of their costs is also consistent with the Commission's policy of holding captive ratepayers harmless as required by state law.

PG&E makes the distinction in its response that its request is limited to a Commission determination that the costs associated with the PPA are eligible for cost recovery from all customers, including departing customers; consistent with Commission decisions.

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.

The Districts' protest concerning the above-market costs of the PPA and PG&E's selection of the Project is misguided

The Districts protest "Any proposal by PG&E to recover the above-MPR costs of the PPA from MDL" and argue that any such a request should be rejected because: "(1) municipal departing load (MDL) will not benefit from the PPA, (2) PG&E has not complied with the least-cost imperative, and (3) because of "perceived uncertainty", no effort will be made by Solel to obtain SEPs to cover the difference between the contract price and the MPR."

In its response, PG&E identifies the Districts' protest as misguided, and we generally agree. Specifically, the Districts confuse "above-market costs" as it relates to PG&E's annual procurement costs to be compared to the annual procurement cost benchmark calculated each year in an ERRA proceeding, and above-market costs associated with the proposed Contract in AL 3092-E, defined as the portion of the contract price that is greater than the market price referent (MPR).

We agree with PG&E that "CPUC approval of Solel procurement costs would not automatically authorize above-market costs in rates".³⁸ Furthermore, we find that PG&E's selection of its contract with Solel complies with the Commission's Least-Cost Best-Fit Decision (see "Discussion" section of this draft resolution). Finally, the Parties decision to forego the CEC's SEP process is justified. That is, by the time that PG&E filed AL 3092-E, deficiencies of the SEP process had been identified and legislation to reform the process was in advanced stages. Most important, the Districts should be indifferent to whether any request to recover costs greater than the MPR is recovered from the CEC or the CPUC.

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:³⁹

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 contract.

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 contract 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 3092-E has near-term milestones; the shortened comment period will allow the Parties to amend their PPA pursuant to D.07-11-025, which modified standard terms and conditions required for RPS contracts, and allow the Seller to proceed with the development of its Project without further delay. 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 moves successfully towards the 20% by 2010 goal, and therefore, clearly serves the public interest. Any harm caused by shortening the comment period by ten 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 agenda 16 days following the mailing of this draft resolution. Comments shall be filed no later than 9 days following the mailing of this draft resolution, reply comments shall be filed no later than 13 days following the mailing of this draft resolution.

Comments were filed on December 13, 2007 by Merced Irrigation District and Modesto Irrigation District, addressing the issue of stranded cost recovery. The Districts also seek further clarity with regards to benefits associated with the PPA and above-MPR cost recovery pursuant to SB 1036. PG&E filed reply comments on the same issues on December 17, 2007. The issues raised by the Districts are currently being explored in R.06-02-013, or should be addressed in another appropriate proceeding, and will not be addressed by resolution.

The Districts point out that the draft resolution incorrectly stated that through their protest of AL 3092-E, the Districts argue that PG&E's PPA with Solel should be rejected. In its protest, the Districts argue that certain requests made by PG&E should be rejected and we make the change here (see page 20).

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 and D.07-11-025 set forth standard terms and conditions to be incorporated into RPS Power Purchase Agreements.

3. On October 14, 2007, Governor Schwarzenegger signed Senate Bill 1036, which has an effective date of January 1, 2008.

4. Senate Bill 1036 will be effective prior to when the proposed contract commences initial deliveries.

5. Senate Bill 1036 authorizes the Commission to provide above-market cost recovery through rates.

6. Pursuant to SB 1036, the approved costs above the MPR may be applied toward the cost limitation.

7. On July 25, 2007, PG&E filed AL 3092-E requesting Commission approval of a renewable procurement contract with SOLEL-MSP-1, LLC (Solel). On November 30, 2007, PG&E filed supplemental AL 3092-E-A.

8. A protest to Advice Letter 3092-E was filed by the Merced Irrigation District and Modesto Irrigation District on August 14, 2007.

9. PG&E responded to the protest on August 21, 2007.

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

11. The protest by Merced Irrigation District and Modesto Irrigation District which concerns above-market costs as it relates to the MPR, and PG&E's selection of the Project is misguided.

12. PG&E's request to recover payments for stranded costs associated with this contract 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.05-07-039 directed the utilities to issue their 2005 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 provided its PRG with reports on this transaction on several occasions between October 24, 2005 and May 30, 2007.

17. D.04-06-014 authorized Energy Division to calculate MPRs for contracts other than 10, 15, or 20 years in length.

18. Energy Division staff calculated a 2005 MPR value for a project with a 25-year term.

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

20. Energy Division reviewed the PPA and finds it reasonable.

21. The Commission has reviewed the proposed contract and finds it to be consistent with PG&E's approved 2005 renewable procurement plan.

22. Solel's proposed all-in contract price is above the 2005 MPR adopted in Resolution E-3980, as modified for a 25-year term.

23. The price reasonableness evaluation discussed in this resolution does not set a precedent for Commission review of RPS contracts.

24. Comments to the Draft Resolution were filed by Merced Irrigation District and Modesto Irrigation District on December 13, 2007.

25. Reply comments were filed by PG&E on December 17, 2007.

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 and D.07-11-025 set forth standard terms and conditions to be incorporated into RPS PPAs.

4. On October 14, 2007, Governor Schwarzenegger signed Senate Bill 1036, which has an effective date of January 1, 2008.

5. Pursuant to Senate Bill 1036, the Commission is authorized to provide above-market cost recovery through rates.

6. Pursuant to SB 1036, the approved costs above the MPR may be applied toward the cost limitation.

7. Pursuant to D.04-06-014, Energy Division is authorized to calculate MPRs for contracts other than 10, 15, or 20 years in length.

8. The methodology Energy Division staff used to calculate a 2005 MPR value for a project with a 25-year term is reasonable.

9. The Commission has reviewed the proposed PPA and finds it to be consistent with PG&E's approved 2005 renewable procurement plan.

10. The PPA is reasonable and should be approved in its entirety.

11. Levelized contract price below the 2005 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.

12. 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, pursuant to SB 1036 and subject to CPUC review of PG&E's administration of the contract.

13. PG&E's request to recover payments for stranded costs associated with this contract should be addressed in R.06-02-013.

14. 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.

15. 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.

16. Procurement pursuant to this PPA constitutes procurement from eligible renewable energy resources 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.), Decision 03-06-071, or other applicable law.

17. Procurement pursuant to this PPA constitutes incremental procurement by PG&E from an eligible renewable energy resource for purposes of determining PG&E'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;

18. AL 3092-E and Supplemental AL 3092-E-A should be approved.

THEREFORE IT IS ORDERED THAT:

1. AL 3092-E and Supplemental AL 3092-E-A are approved.

2. The costs of the contract between PG&E and Solel 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, pursuant to SB 1036 and subject to CPUC review of PG&E's administration of the contract.

3. 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 December 20, 2007; the following Commissioners voting favorably thereon:

_______________

PAUL CLANON

Executive Director

MICHAEL R. PEEVEY

PRESIDENT

DIAN M. GRUENEICH

JOHN A. BOHN

RACHELLE B. CHONG

TIMOTHY ALAN SIMON

Commissioners

REDACTED

Confidential Appendix A

Contract Summary

REDACTED

Confidential Appendix B

Contract Price and Above-Market Cost Analysis

REDACTED

Confidential Appendix C

Contribution to RPS Goals

¹ Seller is pursuing three sites in the following areas, one of which will become the Project Site; (1) Needles, CA, (2) Stedman, CA, and (3) Arrowhead Junction, CA.

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 Note: "above-market costs" refers to the portion of the contract price that is greater than the appropriate market price referent (MPR).

¹⁴ Pub. Util. Code 399.15(d)

¹⁵ Chapter 685, Statutes of 2007 (SB 1036)

¹⁶ http://www.energy.ca.gov/2007publications/CEC-300-2007-002/CEC-300-2007-002-CMF.PDF

¹⁷ http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/48266.pdf

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

²⁰ Pub. Util. Code, Section §399.14

²¹ http://docs.cpuc.ca.gov/word_pdf/FINAL_DECISION/48266.pdf

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

²³ D.04-07-029

²⁴ Submitted to the CPUC on August 22, 2005

²⁵ http://www.caiso.com/docs/2001/12/21/2001122108490719681.html

²⁶ D.07-05-057 Order Modifying Decision 07-02-011 Regarding Definition of Green Attributes http://www.cpuc.ca.gov/word_pdf/FINAL_DECISION/68383.pdf

²⁷ D.07-11-025, Attachment A http://docs.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/75354.PDF

²⁸ On February 1, 2007, PG&E and SCE jointly filed a petition for modification of D.04-06-014. On May 22, 2007, a PD was filed and served. Prior to the PD being voted on by the Commission, PG&E and SCE filed an amended petition for modification of D.04-06-014.

²⁹ http://www.solel.com/files/press-pr/fpl-delivery.pdf

³⁰ http://www.solel.com/

³¹ The facilities are known as Solar Electric Generating System (SEGS) projects I through IX. Luz went bankrupt in 1991; today, FPL Energy owns the majority of the SEGS capacity.

³² 20065 MPR, Resolution E-3980 http://docs.cpuc.ca.gov/WORD_PDF/FINAL_RESOLUTION/55465.PDF

³³ http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/37383.DOC

³⁴ 2004 MPR Resolution: http://www.cpuc.ca.gov/word_pdf/FINAL_RESOLUTION/48242.doc

³⁵ http://www.cpuc.ca.gov/WORD_PDF/FINAL_DECISION/67490.PDF

³⁶ Merced Irrigation District and Modesto Irrigation District protest to Advice 3092-E, filed August 14, 2007.

³⁷ PG&E response to Protest of Merced Irrigation District and Modesto Irrigation District to Advice 3092-E, filed August 21, 2007.

³⁸ PG&E response, August 21, 2007 p. 2

³⁹ PG&E Advice Letter 3092-E, filed July 25, 2007, page 13