Form 8-K filed 10/20/06

Item 8.01 - Other Events

Proposed Decision Approving New Long-Term Generation Resource Commitments

On October 17, 2006, a proposed decision was issued in a proceeding pending at the California Public Utilities Commission (CPUC) that recommends the approval of seven agreements that would provide 2,250 megawatts (MW) of new long-term electricity generation resources in Northern California in accordance with Pacific Gas and Electric Company’s (Utility) 2004-2010 long-term electricity procurement plan. Comments on the proposed decision are due on November 6, 2006. It is expected that the CPUC will issue a final decision by the end of the year.

Proposed Utility-Owned Projects

Two of the agreements provide for third party developers to construct generation facilities to be owned and operated by the Utility. One of these two contracts calls for the construction of a 657-MW power plant to be located in Colusa, California. The other contract calls for the construction of a 163-MW power plant at the Utility’s Humboldt Bay facility to replace the existing power plant at Humboldt Bay, which is at the end of its useful life. As to these contracts, the proposed decision recommends the adoption of an initial capital cost equal to the sum of the fixed contract costs plus the Utility’s estimated owner’s costs. The initial capital costs for these two plants are filed with the CPUC under confidentiality provisions, but are consistent with the Utility’s estimated capital costs range from $900 to $1,100 per kilowatt. The proposed decision recommends the rejection of the Utility’s request to include potential incentive payments to the contractor and contingency amounts that may be incurred by the Utility in connection with unforeseen events in the authorized initial capital costs. Instead, the Utility would be authorized to adjust the initial capital cost to reflect any actual incentive payments paid under the contracts through notification to the CPUC but without a reasonableness review. The Utility’s request to recover other additional capital costs would be subject to a reasonableness review.

The proposed decision’s findings regarding initial capital costs differ from the CPUC’s December 2004 decision that capped cost recovery for construction of utility-owned generation resources at their final bid price and required the utilities to share any construction cost savings with customers while absorbing the full amount of any cost overruns. (In December 2005, the CPUC had indicated that it would revisit its determination regarding the “cost cap” and the sharing of construction cost savings in 2006.) The proposed decision recommends the rejection of the Utility’s request to permit recovery of the above-market costs of the new projects through a non-bypassable charge to be imposed on departing customers for the 30-year life of the project. Instead the proposed decision finds that the 10-year cost recovery period would apply. At the end of this 10-year period, the Utility would still be able to collect any above-market costs from its current full-service customers (known as “bundled” customers), but will no longer be able to charge departing customers for these costs.

In addition, the proposed decision recommends the adoption of the Utility’s estimates of non-fuel operations and maintenance (O&M) costs for the purpose of establishing an initial revenue requirement for the two Utility-owned generation projects. The proposed decision does not accept the Utility’s proposal to include contingency amounts in the authorized revenue requirements for O&M expense. Instead, the proposed decision suggests that the Utility be authorized to adjust the initial revenue requirement through notification to the CPUC for changes to its O&M expense forecast that may occur as a result of (1) increased staffing levels due to permitting requirements, or (2) a change in the commercial operation date, which would change the timing of the O&M expense streams. The proposed decision recommends that the Utility’s requested O&M contingency amounts be placed in a one-way balancing account, which the Utility may recover if and when they are actually expended. The proposed decision notes that a one-way balancing account is appropriate because the new plants

may not become operational until after the Utility’s next general rate case and the Utility should not have to wait to recover these costs until after they have been reviewed in the next general rate case.

The proposed decision notes that the revenue requirement to recover the initial capital costs for the Colusa project will begin to accrue in the Utility Generation Balancing Account (UGBA) as of the date the completed plant is transferred to the Utility, and would be included in rates on January 1 of the following year. The initial revenue requirement for the Humboldt Bay project would begin to accrue in the UGBA as of its commercial operation date, and would be included in rates on January 1 of the following year.

Proposed Power Purchase Agreements

The proposed decision also recommends the approval of five power purchase agreements. The Utility has executed four of these agreements that would provide approximately 800 MW of capacity with terms from 15 to 20 years. The Utility has entered into a letter of intent with an affiliate of Calpine Corporation that provides that the parties would execute the fifth power purchase agreement to provide 601 MW of capacity over a 10-year term if the CPUC approves the agreement and if certain other conditions, including that the associated Calpine Corporation affiliate emerges from bankruptcy or transfers the project assets to a non-bankrupt special purpose entity, are met. The Utility cannot predict whether these conditions will be satisfied or whether the parties will execute a power purchase agreement.

The proposed decision recommends that the Utility be authorized to recover the costs of the power purchase agreements, along with other variable costs, through the Energy Resource Recovery Account, a balancing account 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. If the CPUC approves the agreements and if permitting and construction schedules are met, the new generation facilities are anticipated to begin delivering power to the grid during 2009 through 2010.

General Rate Case

On October 19, 2006, the CPUC approved the Utility’s request in the 2007 General Rate Case (GRC) proceeding to make the revenue requirements ultimately adopted by the CPUC in the proceeding effective on January 1, 2007. The CPUC noted that delays in the proceeding schedule caused by the parties’ good faith settlement negotiations made it unlikely that the CPUC would issue a final decision before January 1, 2007. As previously disclosed, on August 21, 2006, a proposed settlement agreement reached among the Utility, the CPUC’s Division of Ratepayer Advocates, and other parties, was submitted to the CPUC for approval. If approved by the CPUC, the settlement agreement would resolve all of the issues raised by the settling parties and all revenue requirement-related issues raised by other parties. The Utility Reform Network, Aglet Consumer Alliance, and the Alliance for Nuclear Responsibility, together with the Sierra Club, have filed protests to the proposed settlement agreement. PG&E Corporation and the Utility are unable to predict whether the CPUC will approve the settlement agreement.

In addition to the GRC revenue requirement changes, the Utility’s electric and gas distribution rates that will become effective on January 1, 2007 will reflect the same rate of return on equity (11.35%) and the same authorized capital structure (46% long-term debt, 2% preferred stock, and 52% common stock) as were in effect for 2006, as authorized by the CPUC on August 24, 2006 in the Utility’s 2007 cost of capital proceeding.

Renewables Portfolio Standard

On October 19, 2006, the CPUC adopted rules for reporting and determining whether the California Renewables Portfolio Standard (RPS) requirements have been met. The California RPS statute, as amended on September 27, 2006, requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of eligible renewable energy (such as biomass, small hydro, wind, solar and geothermal

energy) by at least 1% of its retail sales per year, so that the amount of electricity purchased from eligible renewable resources equals at least 20% of its total retail sales by the end of 2010. (On September 27, 2006, the California Governor signed into law California Senate Bill 107 to accelerate the deadline to meet the 20% RPS requirement to 2010 from 2017. The CPUC had already adopted the earlier deadline as a matter of policy.)

The RPS statute requires that the CPUC allow retail sellers to use flexible compliance rules to apply excess procurement in one year to meet a following year’s procurement RPS target and to satisfy a deficit in their current year procurement RPS target by deliveries of renewable power within the following three years. The CPUC’s decision confirms that the existing flexible compliance rules apply to procurement through 2009, allowing an excused 2009 deficit to be fulfilled by the end of 2012. The CPUC also stated that the 20% RPS target must be met with actual eligible renewable energy deliveries in 2010 and that a retail seller that has reached the 20% target in a given year is excused from increasing its procurement the next year (or subsequent years) only if it has met its annual procurement target in each of the prior years, or is otherwise excused by the CPUC. The CPUC stated that it will address whether flexible compliance rules apply beyond 2010 in a future decision.

Failure to satisfy the annual requirement after application of the flexible compliance rules may result in a penalty of 5 cents per kilowatt-hour, with an annual penalty cap of $25 million. The exact amount of any penalty and the conditions under which it would be applied are subject to the CPUC’s review of the reasonableness of the utilities’ efforts to meet the requirement. In addition to construction and development risks, whether renewable energy from new generation facilities can be timely delivered is subject to electric transmission constraints.

California	1-12609	94-3234914
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

California	1-2348	94-0742640
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)


	PG&E CORPORATION

Dated: October 20, 2006	By:	G. ROBERT POWELL
		G. ROBERT POWELL Vice President and Controller


	PACIFIC GAS AND ELECTRIC COMPANY

Dated: October 20, 2006	By:	G. ROBERT POWELL
		G. ROBERT POWELL Vice President and Controller