II. Background

A. Progress Towards Resource Adequacy and Long-Term Procurement

The following overview of our resource adequacy long-term procurement decisions sets the context for the action we take today. In D.04-12-048, we approved the LTPPs and signaled our preference for the IOUs to have a mixed portfolio of resources, including contracts that were short, medium and long term in length. While we authorized the IOUs to enter into long-term contracts, we did not order them to do so. It now appears that long-term contracts are necessary to solicit investment in new generation in California.

The Commission opened this rulemaking in February 2006, as a successor proceeding to previous procurement proceedings, R.01-10-024 and R.04-04-003. In D.04-01-050, considered under R.01-10-024, the Commission required each load-serving entity (LSE) within the utilities' service territories to be responsible for procuring, under Commission oversight, sufficient reserves to provide reliable service to its customer's load. In that decision, the Commission had considered a proposal suggested by The Utility Reform Network (TURN) to impose a non-bypassable surcharge so that all customers within the utility service territory would pay their fair share of the costs of acquiring needed reserves. TURN's proposed surcharge would have been similar to other surcharges approved by the Commission, such as SCE's Historic Procurement Charge (HPC) approved in D.02-07-032 and the Cost Responsibility Surcharge (CRS) approved by the Commission in, among other decisions, D.03-07-030. TURN proposed to allow ESPs who have acquired sufficient reserves to "opt-out" of paying this surcharge.

Although the proposed decision in this matter had advocated the adoption of the TURN approach, PG&E, SCE, and other parties raised several implementation issues in their comments. These parties' concerns were that (1) the utilities would be saddled with the cost of acquiring resources for ESPs without the ability to collect from the ESPs, and (2) it would be difficult to procure resources over a longer time-period if ESPs could "opt-out" of the program on a yearly basis. In light of these implementation issues, the Commission modified the proposed decision, and required each LSE to be directly responsible for acquiring its own reserves to meet its own resource adequacy (RA) obligation.

In R.04-04-003, the Commission implemented the resource adequacy requirements (RAR) described in D.04-01-050, through the adoption of RA policies and rules. (See, i.e., D.04-10-035 and D.05-10-042 et seq.) The Commission currently has a forward RAR that is "year-ahead" in nature. Critics have argued, however, that limiting the RAR to the year ahead creates a potential for resource scarcity. The critics portend, for example, if there is not sufficient capacity to meet all the LSEs' demands, one or more LSEs could be caught short. In this hypothetical scenario, PG&E and SCE fear that an ESP unable to meet its RAR because of lack of available capacity will turn back its customers to the IOU. If the entire system is short capacity, then the IOU will be unable to meet its RAR regardless of how well it planned for the needs of its bundled customer load. With a short amount of time between when a shortfall is discovered and when the capacity is needed, no new generation could be brought online in time.

In R.04-04-003, the Commission reviewed and approved the IOUs' LTPPs, and in D.04-12-048, the Commission extended the IOUs' procurement plan authority on a rolling 10-year basis, and authorized the IOUs to enter into short, medium, and long-term contracts provided they complete the required compliance filings. In that proceeding, the IOUs expressed considerable concern regarding the stranded costs that might occur if the IOUs invested in long-term contracts and then experienced a large amount of departing load. In D.04-12-048, Section IV.A.2.a, the Commission discussed the stranded costs issue, as well as the fact that ESPs do not have a business model that supports investment in long-term contracts. The Commission concluded that utilities should be allowed to recover their stranded costs from all customers for a period of either the life of the contract or 10 years, whichever is less. (See D.04-12-048, Conclusions of Law 13-16.)

By establishing a year ahead RAR and determining that departing load was required to pay for stranded cost investments, the Commission had good reason to believe that it had removed barriers to long-term contracting. After D.04-12-048 was issued, both SCE and PG&E issued long-term RFOs. However, in Application (A.) 05-06-003, SCE requested cost-recovery for above-market costs from all customers, not just bundled customers. Evidently, SCE needed assurance that already departed (not just departing) load would pay for the cost of new generation. After issuance of the Scoping Memo limiting the scope of the application, SCE withdrew its application and cancelled its long-term RFO. PG&E continued with its long-term RFO, and recently brought seven contracts to the Commission in A.06-04-012. PG&E has requested similar cost-recovery treatment from all customers for its long-term contracts.

In addition to the fact that PG&E and SCE have not signed any long-term contracts to promote new generation, since the issuance of D.04-12-048, California has not seen sufficient investment from non-utility sources in new generation. The California Independent System Operator's (CAISO) Department of Market Monitoring (DMM) released its assessment of the potential revenues a new generation resource could have earned in California's spot market in 2005. The DMM's April 2006 report indicates that "potential spot market revenues fell significantly short of the unit's annual fixed costs." The DMM looked at costs and expected revenues for both combined cycle and combustion turbine units and concluded that expected revenues do not justify investment in new generation absent long-term contracts:

The DMM's financial assessment of the potential revenues a new generation facility could have earned in California's spot market in 2005 indicates potential spot market revenues fell significantly short of the unit's annual fixed costs. This marks the fourth straight year that the DMM's analysis found that estimated spot market revenues failed to provide sufficient fixed cost recovery for new generation investment. This result underscores the critical importance of long-term contracting as the primary means for facilitating new generation investment.³

The DMM is very concerned about the effect that the lack of long-term contacting is having on California, particularly in Southern California.

Though a significant amount of new generation capacity was added to SP15 in 2005 (2,376 MW) and California realized more new generation investment in 2005 than any other ISO (footnote deleted), new generation investment within Southern California has not kept pace with the significant load growth in that region and unit retirements. This has resulted in a higher reliance on imported power from the Southwest, Northwest, and Northern California. This dependence on imports, coupled with tight reserve margins, makes Southern California very vulnerable to reliability problems should there be a major transmission outage. Moreover, much of the existing generation within Southern California is comprised of older facilities that are prone to forced outages, especially under periods of prolonged operation as occurred during the extraordinarily long heat wave in July, with loads exceeding 40,000 MW for all but two days beginning July 11 and into early August 2005. Additional new generation investment and re-powering of older existing generation facilities would significantly improve summer reliability issues in Southern California but such investments are not likely to occur absent long-term power contracts. The California spot market alone is not going to bring about the major investments needed to maintain a reliable electricity grid.⁴

The CAISO's upcoming Market Redesign and Technology Upgrade (MRTU) is expected to significantly improve the market mechanisms that drive the California's energy markets. It is too early to tell, however, whether MRTU will result in spot market prices and market certainty that will support major investments in new generation without long-term contracts.

The CEC's Transmittal Report for the 2005 IEPR⁵ indicated that there were no regulatory barriers to IOU's engaging in long-term contracting. Many parties have stated that the IOUs appear to be the most-likely entities to sign long-term contracts. However, SCE and PG&E state they are unwilling to sign long-term contracts if it means that their customers are burdened with the above market costs of those units. TURN has stated that it would be unfair to bundled customers to require the IOUs alone to invest in long-term contracts if those contracts cost more than existing generation. Numerous ESPs offer a different perspective. They contend that since DA is currently suspended, DA customers are not responsible for load growth, and therefore, no ESP customers should have to pay for any portion of the needed system expansion.

The above events indicate that we need an additional transitional policy to encourage investment in new generation resources now. Today, we address this issue on an interim basis, and we will address it on a long-term basis in Phase II of the RA proceeding, R.05-12-013.

B. Procedural Background

On February 16, 2006, the Commission initiated this rulemaking to integrate procurement policies and consider long-term procurement plans. To ensure adequate contracting for new resources, we invited proposals on ideas for policies to support new generation and long-term contracts. Proposals were received on March 7^th and 8^th. The Commission scheduled a workshop for March 14, 2006, to discuss the proposals.

The Assigned Commissioner's Ruling on March 29, 2006 permitted parties to comment on proposals discussed and examined at the workshop as well as to offer "new proposals." Comments following the workshop were received on April 10, 2006.⁶ Reply comments were received on April 19, 2006.⁷

³ California Independent System Operator (CAISO), 2005 Annual Report on Market Issues and Performance, April 11, 2006, Executive Summary, ES-2. Available at: http://www.caiso.com/17d5/17d58bdd1270.html.

⁴ Id.

⁵ CEC's IEPR Transmittal Report, November 2005, "Commission Final Transmittal of 2005 Energy Report Range of Need and Policy Recommendations to the California Public Utilities Commission," Publication # CEC-100-2005-008-CMF., December 16, 2005. Available at: http://www.energy.ca.gov/2005_energypolicy/documents/index.html.

⁶ Joint Parties Comments including PG&E, SCE, NRG Energy, Inc. (NRG), TURN; The Coalition of California Utility Employees (CUE) and The Californian Unions for Reliable Energy (CURE); and AES Corporation (AES); Joint comments by Indicated Parties that includes California Large Energy Consumers Association (CLECA, California Manufacturers and Technology Association (CMTA), City and County of San Francisco (CCSF), Coral Power, L.L.C. (Coral), Division of Ratepayer Advocates (DRA), Energy Users Forum, J. Aron & Company (J. Aron), Silicon Valley Leadership Group (SVLG) and Strategic Energy, L.L.C. (Strategic); Aglet Consumer Alliance (Aglet); Alliance for Retail Energy Markets (AReM); California Clean DG Coalition (CCDG); CEC; Californians for Renewable Energy (CARE); CAISO; CLECA and CMTA; Cogeneration Association of California and Energy Producers and Users Coalition (CAC/EPUC); Davis Hydro; DRA; Good Company Associates on behalf of TAS (TAS); Green Power Institute (GPI); Independent Energy Producers Association (IEP); Merced Irrigation District and Modesto Irrigation District (MID); Joint Comments of MID, South San Joaquin Irrigation District, Northern California Power Agency and The California Municipal Utilities Association (Joint POU Parties); Mirant California, L.L.C., Mirant Delta L.L.C. and Mirant Potero L.L.C. (Mirant); PG&E; RCM Biothane (RCM); SDG&E; Sempra Global (Sempra); SVLG; SCE; TURN; Western Power Trading Forum (WPTF); and Women's Energy Matters (WEM).

⁷ Replies were filed by Aglet; AReM; Indicated Parties; CLECA and CMTA; CARE; California Small Business Roundtable (CSBRT) and California Small Business Association (CSBA); CAC/EPUC; Constellation Energy Commodities Group, Inc., Constellation Generation Group, L.L.C. and Constellation Newenergy, Inc.(Constellation); Davis Hydro; DRA; FPL Energy, LLC. (FPLE); IEP; Joint POU Parties; MID; PG&E; SDG&E; Sempra Global; Joint Parties (same as April 10^th); SCE; TURN; WEM.