II. Background

On October 29, 2001, the Commission initiated Rulemaking (R.) 01-10-024 to establish ratemaking mechanisms for California investor-owned electric utilities to resume purchasing electric energy, capacity, ancillary services, and related hedging instruments to meet the needs of their electric customers. This rulemaking proceeding has advanced in stages: On December 19, 2002, the Commission adopted short-term procurement plans for the electric utilities that addressed their procurement activities for 2003, authorized contracts for up to five years, and allowed for the hedging of first quarter 2004 residual net short positions with transactions entered into in 2003.¹ On April 15, 2003, the utilities filed 20-year LTRPs covering their anticipated procurement needs between 2004 and 2023. On May 15, 2003, the utilities filed short-term procurement plans for their anticipated procurement plans for 2004. On December 18, 2003, the Commission adopted the utilities' 2004 short-term procurement plans in D.03-12-062, and in D.04-01-050, issued January 22, 2004, adopted a long-term regulatory framework for the utilities to plan for and procure their energy resources and demand-side investments for the future.

Simultaneously with the Commission's actions to address the electric utilities resource needs, the Legislature passed Assembly Bill (AB) 57, which was signed by Governor Davis on September 24, 2002, that requires electric corporations to have a diversified procurement portfolio with short-term and long-term electricity and electricity-related and demand reduction products. AB 57 added § 454.5 to the Public Utilities Code (Pub. Util. Code).²

In summary, § 454.5 states that an electric utility's procurement plan may include a competitive procurement process under which the utility may request bids and the Commission will provide an expedited approval process for proposed contracts so a utility will know the upfront standards and criteria for rate recovery for a proposed procurement contract prior to execution of the transaction. In D.02-10-062, the Commission adopted a framework with requirements for the utilities to follow when updating their procurement plans that includes an expedited review process to comply with the requirements of AB 57 and § 454.5.

A. San Diego Gas & Electric Company

When SDG&E analyzed its LTRP, the utility determined that additional capacity conforming to the Independent System Operator (ISO) grid reliability criteria was needed starting in 2005. Following the AB 57 guidelines, as codified in § 454.5, SDG&E conducted a competitive procurement process by issuing an RFP on May 16, 2003. The RFP requested bids from all qualified resources, including turn-key natural gas-fired generating units, power purchase agreements (PPA), demand reduction products, renewable resources, and any combination of those resources.

After receipt and review of the proposals it received in response to its RFP, SDG&E selected six recommended proposals³ for approval by the Commission and filed a motion on October 7, 2003, seeking authorization to enter into these new electric resource contracts and for approval of the associated cost recovery and ratemaking mechanisms. SDG&E's October filing included both "redacted, public versions" and "unredacted confidential versions" of testimony. Pursuant to a December 1, 2003, ruling by Administrative Law Judge (ALJ) Walwyn, on December 11, 2003, SDG&E filed revised versions of its submittals that included information in the public versions that had previously been redacted.

Intervenor testimony was served by: The Utility Reform Network (TURN) and Utility Consumer Action Network (UCAN), Celerity Energy, Inc. (Celerity), InterGen NV (InterGen), Calpine Corporation (Calpine), Office of Ratepayer Advocates (ORA), and rebuttal testimony was served by SDG&E and Sempra Energy Resources (SER), and Calpine.

Evidentiary hearings were held February 9-20, 2004. Post-hearing briefs were filed by: SDG&E, SER, TURN and UCAN, ORA, Pacific Gas and Electric Company (PG&E), Calpine, Celerity, Coral Power, LLC, (Coral), Dynegy Marketing and Trade (Dynegy), Intergen, and Nevada Hydro Company, Inc. and the Elsinor Valley Municipal Water District (Nevada Hydro).

The proposed decision (PD) of ALJ Brown and the alternate proposed decision (APD) of President Peevey were mailed on April 6, 2004. Comments were received on April 26, 2004 from California Independent System Operator Corporation (CAISO), Calpine, Celerity, Dynegy, Intergen and Coral, Nevada Hydro, ORA, PG&E, SDG&E, SER and the City of Escondido, and TURN/UCAN. Reply comments were received on May 3, 2004, from CAISO, Ratepayers for Affordable Clean Energy, Calpine, Dynegy, ORA, SDG&E, and SER and the City of Escondido.

On May 13, 2004, an APD by Commissioner Wood (Wood alternate) was mailed to the parties. Comments were received May 20, 2004, and reply comments were received May 25, 2004.

In response to the comments and reply comments received on April 26 and May 3, 2004, the PD has been modified. Many of the changes are simply corrections and clarifications, but others are substantive. In particular, the following changes are viewed as significant: SDG&E is authorized to complete

contract negotiations with Celerity on the terms that the parties had agreed to in September 2003; the Comverge proposal needs to be modified to include a residential component, and the cost sharing mechanism between SDG&E and Comverge is 50/50 with a payment cap; the heat rate incentive for Palomar is modified; and for the two turn-key projects, Ramco and Palomar, all customers of SDG&E that are currently ineligible for direct access are obligated to pay for stranded costs of these generation projects for the next ten years. In addition, the revised PD clarifies that SDG&E's ROE for generation assets, including Ramco and Palomar, is 10.90% and no changes to the ROE are approved at this time.

Although the revised PD does not adopt a lot of the ratemaking proposals SDG&E requested for the Ramco, Palomar, and Otay Mesa projects, we do specify that SDG&E may make in-lieu franchise fee payments to Escondido, or any other similarly situated city, when ownership of Palomar transfers from SER to SDG&E.

We also urge SER to renegotiate its DWR contract.

B. The Basis for SDG&E's RFP

SDG&E testified that it designed the Grid Reliability RFP to acquire capacity to address the anticipated grid reliability shortfall identified in its LTRP, as well as to reduce the costs of its Reliability Must Run (RMR) obligations and to meet load and planning reserves.^{4 5}

SDG&E's service area geographically covers all of San Diego County and the southernmost one-third of Orange County. This region defines SDG&E's local reliability area (LRA) and the utility's local reliability requirement is a function of the demand forecast for the LRA. SDG&E is required to meet the ISO's statewide grid planning criteria, which includes a G-1/N-1 criterion.⁶ For the purpose of SDG&E capacity planning, the utility is required to have sufficient on-system resources and import capability to serve the full adverse peak summer demand forecast of the LRA during the worst G-1/N-1 event.⁷

SDG&E's witness David M. Korinek testified that using the ISO's G-1/N-1 criterion, SDG&E determined late in 1999 that it would experience a reliability shortfall by 2004. SDG&E then proposed a new 500 kV transmission interconnection project, Valley-Rainbow, that was rejected by the Commission in D.02-12-066. Korinek further stated that when this project was rejected, the utility realized it would face a reliability shortfall beginning in summer 2005, and continuing through 2007. The utility knew that no new generating plants have been built in SDG&E's service area, none are currently under construction, and the utility did not anticipate that it could complete licensing and construction of any new interconnection proposals prior to 2008.

C. Preparation and Circulation of the RFP

Based on the foregoing analysis, SDG&E issued its RFP to procure resources to meet its additional reliability capacity needs for at least 2005-2007. As stated above, the RFP sought proposals from all qualified resources in the market place. Because of the existing import limitations at San Onofre and Miguel, the two sources of delivery of imported capacity to the utility's LRA, the RFP specified that"[p]roposed resources must be located within SDG&E's service territory . . . or have generator transmission system interconnection (gen-tie) directly interconnected to the electric network internal to SDG&E's service area."

In order to have the benefit of outside consultants in the design of the RFP and in the evaluation of the proposals, SDG&E retained the services of Sargent & Lundy, LLC (S-L). S-L is an engineering company that serves the power industry solely, and S-L worked with SDG&E personnel on the actual RFP document and performance specifications, assisted the utility with gas-fired resources, and developed the RFP project website.⁸ Once the RFP was in draft form, SDG&E

provided it to its Procurement Review Group (PRG)⁹ for review and comment. After receiving input from the PRG, and making appropriate adjustments, the RFP was issued on May 16, 2003.

Thomas, a SDG&E witness on the RFP, testified that the RFP was sent to over 170 market participants, cited in Platts Megawatt Daily, and posted on SDG&E's website.¹⁰

Bids were originally due July 14, 2003, but the date was accelerated to June 27, 2003, to accommodate SDG&E's response to a motion filed by Calpine seeking an expedited order authorizing SDG&E to negotiate a PPA with Calpine for the Otay Mesa facility.¹¹ SDG&E stated that it wanted the RFP bids in before the Commission ruled on Calpine's motion because SDG&E wanted to review all the competitive bids to assess all available alternatives for meeting its resource needs.

Bids were submitted by respondents to the RFP project website, reviewed by S-L, then dispursed to SDG&E's lead procurement analysts to identify the bids that met SDG&E's primary and secondary threshold criteria. The primary threshold criteria were: firm delivery; dispatchable resource; location (tied to SDG&E's grid as described in the RFP); available by June 1, 2007. The secondary threshold criteria were: technology and operational flexibility; reliability; development risk; respondent's corporate capabilities and experience; and ability to meet schedule.¹² Proposals that met the threshold requirements were then evaluated on a least cost/best fit (LCBF) analysis. As described in the direct testimony of Thomas for SDG&E, LCBF is a process of evaluating resources relative to the existing, and known future, demand and supply-side resources within SDG&E's portfolio, taking into account integration with the transmission system.¹³

D. Bid Evaluation

By the initial bid submittal date of June 27, 2003, SDG&E received 22 bids. Thirteen appeared to conform to the RFP and the utility submitted these to its PRG for review. The conforming bids were categorized into demand response, renewable resources, and fossil fueled resources for further evaluation. Thomas testified that once the conforming bids were identified, those bidders were sent clarifying questions, data requests, and requests for supplemental bids. Thomas stated that the utility maintained confidentiality of the bids by limiting the sharing of bid information to key task leaders, their respective supporting staff, and senior management. Maintaining bid confidentiality was critically important because a SDG&E affiliate, SER, was a conforming respondent. SDG&E maintained that it took steps to maintain a "level playing filed" in reviewing and evaluating the bids so as not to advantage SER in anyway. In addition, Thomas attested that the utility took several measures to ensure that the affiliate transaction rules (ATR) were diligently followed.¹⁴

Because SDG&E was considering a bid submitted by its affiliate, SER, before negotiations began in earnest with SER, SDG&E retained the services of Dr. James Boothe to function as an independent observer of the negotiations. Dr. Boothe was to observe the process and then file a report addressing his perceptions of the fairness of the negotiations.¹⁵

Thomas stated that of the original 22 bids, eight fossil fueled capacity were determined to be non-conforming, two of the four demand response resource bids were non-conforming, and three of the five renewable bids were non-conforming.

The bids that were found to be conforming were evaluated first against the threshold requirements and then on the basis of LCBF, with importance given to overall resource portfolio cost for capacity and energy delivered and transmission system upgrade costs necessary for the generation resource to satisfy grid reliability requirements. The utility stated that it placed high emphasis on proposal pricing in its evaluations, not only in terms of the initial cost, but also the long-term costs. For the gas-fired generation proposals, SDG&E determined that a 30-year evaluation process was appropriate.¹⁶

Thomas explained how the bid evaluation process systematically eliminated less attractive proposals. The remaining bids were then evaluated using the following steps: (1) the proposals were categorized by energy product type: demand reduction, renewable, or other supply side resources; (2) each energy product type was then ranked by total cost, exclusive of transmission system expansion costs and gas supply costs; (3) with the PRG's approval preference was given to renewable and demand response resources that met threshold criteria and had reasonable costs; (4) the remaining grid capacity needs were determined and assessed relative to cost and portfolio fit; (5) SDG&E's production cost model was then applied to assess the energy delivery characteristics of the bids; (6) the proposals were evaluated relative to the anticipated transmission network upgrade costs attributable to the addition of the generation resource at the location identified by each respondent; (7) the proposals were ranked relative to a total cost basis that included capacity, energy, and transmission costs; and (8) if two bids had the same overall cost, the following qualitative factors were applied: benefits to minority and low income areas; resource diversity; environmental stewardship; ability to advance schedule; technology and operational flexibility; reliability; development risk; financing plan; corporate capabilities, credit, and proven experience.¹⁷

E. Proposed Projects Resulting From the RFP Process

At the completion of the bid review and examination, and follow-up negotiations, SDG&E determined that the five proposals were needed to meet its grid reliability needs or long-term resource: One demand reduction program, Comverge; one renewable project, Envirepel; and three gas-fired facilities that include one combustion turbine intermediate unit, Ramco; and two combined cycle power plants, Palomar and Otay Mesa. Ramco and Palomar are turnkey operations giving SDG&E utility ownership of the generation, and Otay mesa is a 10-year PPA. As part of its proposal for Otay Mesa, SDG&E requests that the Commission also authorize three conditions: the reallocation of the DWR/Sunrise contract,¹⁸ expedited review of its application for transmission upgrades,¹⁹ and approval of additional equity to the utility's capital structure to offset the negative debt impacts of the PPA.