Pacific Gas & Electric (PCG)

Electricity Generation Resources

California legislation has been enacted which allows the Utility to recover its reasonably incurred wholesale electricity procurement costs and includes a mandatory rate adjustment provision that requires the CPUC to adjust rates on a timely basis to ensure that the Utility recovers its costs.

Procurement Cost Balancing Account and Mandatory Rate Adjustments

Effective January 1, 2003, as authorized by California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the authorized revenue requirement and actual costs incurred under the Utility’s authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned utility’s electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the forecast aggregate over-collections or under-collections exceed 5% of the utility’s prior year electricity procurement revenues, excluding amounts collected for the DWR. The Utility’s ERRA trigger threshold for 2004 is $191 million. As of December 31, 2004, the ERRA had an under-collected balance of approximately $75 million, which is below the 5% trigger for mandatory adjustment of rates. The CPUC approved an ERRA revenue requirement of $2.189 billion for 2004. In its 2005 ERRA application filed in June 2004, the Utility requested a forecast revenue requirement of $2.140 billion and the authority to amortize routine over and under-collections in the ERRA annually to coincide with January 1 rate changes. In December, 2004, the CPUC approved the Utility’s Annual Electric True-up filing, under which the under-collections and over-collections in the Utility’s electric-related balancing accounts, including the under-collection in the ERRA, are authorized to be recovered in the Utility’s 2005 electric rates. A final decision on the 2005 ERRA application is expected in the first quarter of 2005.

Electricity Generation Resources

        California legislation has been enacted which allows the Utility to recover its reasonably incurred wholesale electricity procurement costs and includes a mandatory rate adjustment provision that requires the CPUC to adjust rates on a timely basis to ensure that the Utility recovers its costs.

Procurement Cost Balancing Account and Mandatory Rate Adjustments

        Effective January 1, 2003, as authorized by California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned utility's electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the forecast aggregate over-collections or under-collections exceed 5% of the utility's prior year electricity procurement revenues, excluding amounts collected for the DWR. The Utility's ERRA trigger threshold for 2004 is $191 million. As of December 31, 2004, the ERRA had an under-collected balance of approximately $75 million, which is below the 5% trigger for mandatory adjustment of rates. The CPUC approved an ERRA revenue requirement of $2.189 billion for 2004. In its 2005 ERRA application filed in June 2004, the Utility requested a forecast revenue requirement of $2.140 billion and the authority to amortize routine over and under-collections in the ERRA annually to coincide with January 1 rate changes. In December, 2004, the CPUC approved the Utility's Annual Electric True-up filing, under which the under-collections and over-collections in the Utility's electric-related balancing accounts, including the under-collection in the ERRA, are authorized to be recovered in the Utility's 2005 electric rates. A final decision on the 2005 ERRA application is expected in the first quarter of 2005.

        The CPUC performs periodic compliance reviews of the procurement activities recorded in ERRA to ensure that the Utility's procurement activities are in compliance with its approved procurement plan. If the CPUC determines that the Utility's procurement activities were not in compliance with its approved procurement plan, some of the Utility's procurement costs could be disallowed. Procurement activities related to DWR allocated contracts could be disallowed up to a maximum of two times the Utility's administration costs associated with procurement, or $36 million for 2004. The Utility and the CPUC's Office of Ratepayer Advocates, or the ORA, have agreed that there should be no disallowances in the Utility's ERRA proceeding reviewing procurement activities during the period from January 1, 2003 through December 31, 2003, and have jointly recommended that the CPUC close the record period. PG&E Corporation and the Utility are unable to predict whether a disallowance will result or the size of any potential disallowance. In addition, it is uncertain whether the CPUC will modify or eliminate the maximum disallowance for future years.

New Long-Term Generation Resource Commitments

        As discussed in the "Overview" section above, in December 2004, the CPUC issued a final decision which approved, with certain modifications, each investor-owned electric utility's LTPP in order to authorize each utility to plan for and procure the resources necessary to provide reliable service to their customers for the ten-year period 2005-2014. The decision recognizes that each utility will have capacity needs over the ten-year period, especially in 2011 when most of the electricity

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purchase contracts entered into by the DWR expire. In January 2005, several parties submitted applications for rehearing of the December 2004 CPUC decision. The Utility is unable to predict how or when the CPUC will respond to those applications.

        In the LTPP filing the Utility assumed, under a medium load scenario, that:

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By 2014, its procurement responsibility would be reduced by approximately 4,000 megawatts, or MW; and



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Power plants currently providing 2,000 MW of generation to the Utility would retire within the next five or six years.

        In addition, the LTPP reflects that all California investor-owned electric utilities are required to achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006.

        The CPUC may require the Utility, or the Utility may elect, to satisfy all or a part of the resources necessary to meet their customers' energy needs by developing or acquiring additional generation facilities or by entering into long-term power purchase agreements. The December 2004 CPUC decision requires the utilities to solicit bids from providers of all potential sources of new generation (e.g., conventional or renewable resources to be provided under utility owned projects or turnkey developments, or buyouts, or under third party power purchase agreements) through a single, open, transparent and competitive request for offers, or RFO, process, although a utility can tailor a RFO to meet specific resource needs. The CPUC requires the utilities to use an independent evaluator to review the RFO process. Before the CPUC decision was issued, the CPUC had approved the Utility's solicitation of offers for utility-owned generation development and for generation to be provided under long-term power purchase agreements for approximately 1,200 MW of peaking resources by 2008 and an additional 1,000 MW of load-following resources by 2010. The Utility issued two RFOs in November 2004 for these resources. In order to incorporate elements of the CPUC's December 2004 decision, the Utility notified bidders on January 7, 2005 that it was deferring its RFOs to evaluate how to incorporate new RFO requirements adopted by the CPUC. The Utility expects to issue updated RFOs in March 2005 and request initial bids to be submitted in April 2005. It is anticipated that contracts for the winning bidders would be submitted to the CPUC for approval in the second half of 2005. Completed projects could result in rate base additions in 2008.

        To help assure recovery of the Utility's cost of new long-term resource commitments, the CPUC adopted a non-bypassable charge to be collected from all customers on whose behalf the Utility makes these new commitments, including those who subsequently receive generation from other load-serving entities.

        In addition, in its decision approving the LTPP, the CPUC recognized that credit rating agencies will consider obligations under long-term procurement contracts to have debt-like characteristics that will adversely affect the Utility's credit ratios, which may, in turn, adversely affect the resulting credit ratings. The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ S&P's method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%. As the Utility enters into contracts with counterparties, the Utility will be exposed to the risk that counterparties will fail to perform and associated business credit risks.

        The CPUC also determined that for utility-owned generation resources, the utilities are prohibited from recovering initial capital costs in excess of their final bid price. If final project costs are less than the final bid price, the savings would be shared with customers, while any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by a utility would be eligible for cost-of service ratemaking treatment.

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        If the Utility is not able to recover a material part of the cost of developing or acquiring additional generation facilities in rates in a timely manner, PG&E Corporation's and the Utility's financial condition and results of operations would be materially adversely affected.

Renewable Energy

        California law requires that, beginning in 2003, each California retail seller of electricity, except for municipal utilities, must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal be met by 2010. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewable energy purchases to approximately 800-900 GWh. Based on the medium load scenario in the Utility's long-term electricity procurement plan, the Utility believes that it can meet the accelerated goal.

DWR Allocated Contracts

        The Utility acts as a billing agent for the collection of the DWR's revenue requirements from the Utility's customers. The DWR's revenue requirements consist of a power charge to pay for the DWR's costs of purchasing electricity under its contracts and a bond charge to pay for the DWR's costs associated with its $11.3 billion bond offering completed in November 2002. In December 2004, the CPUC issued a decision on the permanent cost allocation methodology for the DWR's power charge revenue requirements in 2004 and subsequent years, among the three California investor-owned electric utilities. The Utility's customers' share of 2004 DWR power charge revenue requirement is approximately $1.7 billion after consideration of the DWR power charge adjustment to implement this decision. The Utility's customers' share of 2004 DWR bond charge revenue requirement is approximately $369 million. In January 2005, the CPUC granted limited rehearing of its permanent cost allocation decision to address how to calculate the above-market costs of the DWR power contracts. A final decision on DWR permanent cost allocation is expected in the first quarter of 2005. The Utility cannot predict the final outcome of this matter. As a result of the transition from frozen rates and the electricity procurement recovery mechanism described below, the collection of DWR revenue requirements, or any adjustments thereto, should not affect the Utility's results of operations.