[ ]		Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
[ ]		Soliciting Material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
[ ]		Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)
[ ]		Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 1.01 – Entry into a Material Definitive Agreement

A.     Amendments to Non-Qualified Deferred Compensation Plans

On December 15, 2004, the respective Board of Directors of PG&E Corporation and Pacific Gas and Electric Company (Utility) took action with respect to the deferred compensation plans described below to comply with requirements of the American Jobs Creation Act signed into law on October 22, 2004 (Act).  The Act generally applies only to amounts deferred in 2005 or later.  It is expected that the U.S. Department of Treasury will publish guidance by December 22, 2004 on a number of issues and will issue transition rules before the end of the year to allow, for a limited period, plans to be amended (a) to permit cancellation of an existing deferral election applicable to post-2004 deferrals and (b) to conform with the new guidance for post-2004 deferrals.  The Boards of Directors of PG&E Corporation and the Utility have delegated to the Chief Executive Officer of PG&E Corporation and to the Chairman of the Board of the Utility the authority, within certain parameters, to make such additional amendments to the deferred compensation plans as may be necessary to conform to the new rules.

PG&E Corporation Supplemental Retirement Savings Plan (SRSP).  The SRSP has been the principal deferred compensation plan for key employees of PG&E Corporation and the Utility.  As several of the provisions of the SRSP would not  comply with the Act, existing accounts under the SRSP will be frozen effective December 31, 2004.  The rules of the existing SRSP, including rules with regard to distribution elections, will generally continue to govern amounts deferred before January 1, 2005.   

The Board of Directors of PG&E Corporation adopted a new SRSP to become effective as of January 1, 2005.  The new SRSP will allow key employees of PG&E Corporation or the Utility to defer between 5% to 50% of their salary, and all or a portion of their bonus payments, perquisite allowances, and certain performance-based payments under the PG&E Corporation Long-Term Incentive Program.  Participant accounts also are credited with amounts that cannot be provided through PG&E Corporation’s tax-qualified defined contribution plan (the PG&E Corporation Retirement Savings Plan), due to legal limitations associated with highly-compensated employees.  The new SRSP complies with the Act in that the new SRSP requires that deferral elections generally must be made in the year prior to the year that services were performed to earn the compensation. 

Amounts credited to participants’ accounts include gains or losses attributable to the deemed investment in one or more deemed investment options, including phantom shares of PG&E Corporation common stock.  The amounts credited to a participant’s account under the SRSP represent an obligation of PG&E Corporation to make payments to the participant at some time in the future.  PG&E Corporation’s deferred compensation obligations under the SRSP are unsecured general obligations of PG&E Corporation payable from its general assets and rank equally with its other unsecured and unsubordinated indebtedness from time to time outstanding.  

Distributions from the new SRSP may generally occur only as originally selected at the time of deferral at a date or dates specified or in connection with separation from service.  In addition, distributions are permitted in the event of an unforeseeable emergency (as defined in the Act).  Changes in distribution elections may only occur within the limits of the Act.

Pacific Gas and Electric Company Supplemental Executive Retirement Plan (SERP).  The Utility SERP is a non-tax-qualified defined benefit pension plan that provides officers and key employees of PG&E Corporation and the Utility with a pension benefit based on a combination of base pay and annual incentive payments.  The Utility SERP benefit is offset by amounts received from the Utility’s tax-qualified defined benefit pension plan.  The Utility SERP differs from the Utility’s tax-qualified defined benefit pension plan in that it provides a pension based upon a percentage of final pay that includes bonus payments.  To comply with the Act, the Board of Directors of the Utility has amended the Utility SERP to eliminate all forms of distribution other than a life annuity option consistent with the options provided under the tax-qualified defined benefit pension plan.  Distribution elections made before January 1, 2005 are not affected.  The Board of Directors of PG&E Corporation also has adopted a new SERP that complies with the Actand has transferred the obligations for current active employees who participate in the Utility SERP and for future retirees to PG&E Corporation from the Utility. 

PG&E Corporation Officer Severance Policy (Policy).  The Policy provides for a severance benefit for certain officers of PG&E Corporation and its subsidiaries, including the Utility, whose employment is severed “not for cause.”  The benefit is a multiple of base and target annual incentive, as well as continued vesting of equity awards for a specified period of time.  The Board of Directors of PG&E Corporation has amended the Policy to provide that, with respect to terminated officers who are not retirement eligible (age 55), their severance benefit, if sufficient, will be automatically converted to provide for an immediately payable pension annuity with the remainder, if any, of the severance benefit paid in a lump sum.  If the severance benefit is insufficient to convert into an immediately payable pension, or the terminated officer is at least 55 years old, the entire severance benefit will be paid in a lump sum.

PG&E Corporation Deferred Compensation Plan for Non-Employee Directors.  This plan permits non-employee directors of PG&E Corporation and the Utility to defer all or a portion of their retainers and meeting fees.  Amounts credited to participants’ accounts include gains or losses attributable to the deemed investment in one or more deemed investment options, including phantom shares of PG&E Corporation common stock.  The amounts credited to a participant’s account represent an obligation of PG&E Corporation to make payments to the participant at some time in the future.  PG&E Corporation’s deferred compensation obligations are unsecured general obligations of PG&E Corporation payable from its general assets and rank equally with its other unsecured and unsubordinated indebtedness from time to time outstanding.  The Board of Directors has amended this plan to permit hardship distributions and changes in existing distribution elections, consistent with the provisions of the Act.   These features also are consistent with the features included in the new SRSP. 

B.      Approval of 2005 Short Term Incentive Plan

On December 15, 2004, the Nominating, Compensation and Governance Committee (Committee) of the PG&E Corporation Board of Directors approved the structure of the 2005 Short-Term Incentive Plan (STIP) under which officers of PG&E Corporation and the Utility are provided an opportunity to receive annual incentive cash payments.  For PG&E Corporation executive officers, the STIP award will be based entirely on the achievement of financial objectives, as measured by earnings from operations.  The executive officers of the Utility will have an opportunity to receive annual cash incentives based on three criteria:  the achievement of financial objectives as measured by PG&E Corporation’s earnings from operations (weighted 25%), the Utility’s contribution to PG&E Corporation’s earnings from operations (weighted 50%), and the success of key strategic initiatives (weighted 25%).  Recommendations as to the specific performance scales for each STIP award component will be presented for the Committee’s action at its February 2005 meeting.  The Committee will continue to retain full discretion as to the determination of final officer STIP awards.

Item 8.01 Other Events

A.      Final Decision in Cost of Capital Proceeding

On December 16, 2004, the California Public Utilities Commission (CPUC) issued a final decision approving a return on common equity (ROE) for the Utility of 11.22% for 2004 and 2005,which is consistent with the December 19, 2003 settlement agreement entered into between the CPUC, the Utility and PG&E Corporation to resolve the Utility’s Chapter 11 proceeding (Settlement Agreement).  The Settlement Agreement provides that, from January 1, 2004 until certain credit ratings are achieved, the Utility’s authorized ROE will be no less than 11.22% per year.  The Settlement Agreement also provides that the authorized equity ratio of the Utility’s capital structure for ratemaking purposes will not be less than 52%, except that for 2004 and 2005 it may not be less than 48.6%.  The decision authorizes the following cost of capital for 2004 and 2005:

As a result of the decision, the Utility’s annual revenue requirement for 2004 has decreased by approximately $109 million compared to the currently authorized revenue requirement, as a result of interest savings associated with the Utility’s Chapter 11 exit financing.  This decision will not have an impact on the Utility’s financial results for 2004 because the Utility has previously recorded a reserve against operating revenues for the difference between its currently authorized rate of return on rate base of 9.24% and the lower rate of return on rate base of 8.53% that has now been approved.

The decision also recognizes the importance of assessing and mitigating the debt equivalence impacts on the Utility’s and the two other California investor-owned electric utilities’ (IOUs) credit ratings associated with the long-term financial obligations under power purchase agreements (PPAs) that the IOUs will be required to enter into to meet electricity resource adequacy requirements.  Although the decision does not adopt a formal debt equivalence policy, the CPUC recommends that the IOUs submit detailed information in their future cost of capital applications so that the CPUC can assess the debt equivalence impacts.  Additionally, the decision states that the IOUs should also make recommendations for improving and maintaining their credit ratings.

B.  Final Decision on Long-Term Electricity Resource Plans

On December 16, 2004, the CPUC issued a final decision which approved, with certain modifications, each IOU’s long-term electricity procurement plan (LTPP) in order to authorize each IOU 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 IOU will have capacity needs over the ten-year period, especially in 2011 when most of the electricity purchase contracts entered into by the California Department of Water Resources (DWR) and allocated to the IOUs’ customers expire.  The decision states that a major issue in the proceeding is the extent to which the IOUs will be compensated for investments or purchases that they must make in order to meet their obligation to provide reliable service to their customers, noting that the implementation of community choice aggregation, departing municipal load, and the potential for allowing new direct access all create a great degree of uncertainty as to the amount of load the existing IOUs will be responsible for serving in the future.  The decision includes the following key points:

• The decision finds that the Utility’s strategy of adding 1,200 megawatts (MW) of reserve capacity and new peaking generation in 2008 and an additional 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers (RFOs) is reasonable and compatible with the Utility’s resource needs under its medium preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty.  However, the decision notes that the Utility’s procurement commitments may need to be increased or expedited for the Utility to meet the accelerated 2006 resource adequacy obligations recently approved by the CPUC.

• To meet the IOUs’ resource requirements, the IOUs are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements (PPAs)) through a single, open, transparentand competitiveRFO process, although an IOU can tailor a RFO to meet specific resource needs.  In particular, bids for long-term generation resources (whether PPAs or Utility-owned) would be evaluated side-by-side.  In evaluating bids, the IOUs are required to:
•  

  • procure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources,
  • employ the Least-Cost Best-Fit methodology when evaluating bids for PPAs and utility-owned generation resources, taking into account the qualitative and quantitative attributes (such as performance risk, credit risk, price diversity, term, and operational flexibility) associated with each bid, and
  • employ a “greenhouse gas adder” to evaluate fossil-fuel generation bids as a method to recognize the cost of greenhouse gas emissions to develop a more accurate price comparison between fossil-fuel, renewable and demand-side bids (the greenhouse gas adder would be used for analytical purposes only and would not be paid to a generator). 
    
• When evaluating PPA bids, the IOU is required to employ Standard & Poor’s (S&P’s) method of assessing the debt equivalence impacts on the IOU’s credit ratings, but instead of using 30% of the present value of the fixed capacity payments due under a PPA as the debt equivalent as S&P’s method does, the factor would be reduced to 20%.  As described above in the description of the final decision in the cost of capital proceedings, the CPUC will consider the debt equivalence impact of PPAs on the IOUs' credit ratingsin their future cost of capital proceedings.
  
• IOUs are prohibited from recovering initial capital costs in excess of their final bid price for utility-owned generation resources.  If final project costs are less than the final bid price, the savings would be shared with ratepayers and any cost overruns would be absorbed by the IOUs.  Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by an IOU would be eligible for cost-of service ratemaking treatment.

• Affiliates of the IOUs are permitted to participate in the bidding process for long-term generation resources, subject to certain guidelines and safeguards, including a requirement that the IOUs use an independent third party evaluator in resource solicitations where there are bids that involve affiliates or IOU-built or IOU-turnkey development projects.  The independent evaluator will not be able to make binding decisions on behalf of the IOUs. 

• IOUs are permitted to recover their net stranded costs of all new fossil-fuel and renewable generation resources from all customers, including departing customers, for a period of 10 years or the life of the PPA, whichever is less, provided that the CPUC will allow the IOUs an opportunity to justify a longer recovery period on a case-by-case basis.  The 10-year recovery limit will not apply to stranded costs that may be incurred under renewable energy contracts entered into by an IOU to achieve its target under the Renewables Portfolio Standard, but, unless a longer recovery period is justified by the IOU, the ten-year recovery period limit will apply to PPAs for renewable energy entered into as a result of an open all-source RFO process.  IOUs are required to take appropriate steps to minimize potential stranded costs by selling excess energy and capacity needs into the marketplace and crediting the revenues from these sales against the IOUs’ costs.

• The mandatory rate adjustment mechanism under California Assembly Bill 57 (AB 57), which otherwise would cease on January 1, 2006, has been extended to the length of a resource commitment or 10 years, whichever is longer.  Under the mandatory rate adjustment mechanism the CPUC is required to review the revenues and costs associated with an IOU’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 IOU’s prior year electricity procurement revenues, excluding amounts collected for the DWR. 

• With respect to the IOUs’ contracting authority, the decision permits the IOUs to enter into short-term, mid-term and long-term contracts with starting delivery dates through 2014, provided the IOUs submit necessary compliance filings and provided that contracts with terms five years or longer are submitted to the CPUC for pre-approval.  The decision adopts a rolling 10-year procurement period, noting that the LTPs cover a 10-year period and will be updated and reviewed every 2 years.  The decision grants the Utility’s petition for modification of its existing short-term procurement plan to permit the IOUs to conduct procurement using negotiated bilateral agreements for transactions up to 3 calendar months, or one quarter, forward.  The decision notes that ultimately the CPUC will eliminate short-term procurement plans and the IOUs will act in accordance with a single CPUC-approved plan; but until then, the IOUs’ existing short-term plans remain in effect and any updates or modifications should be filed with an advice letter within 30 days after the issuance of the decision.  The decision requires the IOUs to submit a compliance filing updating their procurement plans to reflect the changes and modifications in the decision by March 25, 2005.

• The decision directs the IOUs to meet CPUC-mandated energy efficiency goals over the 10-year  period, but does not authorize the $245 million incremental revenue requirement requested by the Utility to fund energy efficiency programs for 2006 through 2008.  Instead, the decision defers this issue for consideration in the CPUC’s energy efficiency rulemaking proceeding.

• The decision denies the Utility’s request to clarify that the maximum annual procurement disallowance established by the CPUC for the Utility’s administration of the DWR allocated contracts and least-cost dispatch of its electricity resources of two times the Utility’s administration costs of managing procurement activities, be extended to the Utility’s administration of all utility dispatch, including allocated DWR contracts and administrative and dispatch costs related to utility-owned generation and other PPAs.

C.  Final Decision in the Utility’s Gas Accord III

Also, on December 16, 2004, the CPUC issued a final decision approving the Gas Accord III Settlement Agreement which: resolves all issues in this proceeding; sets the Utility’s gas transmission and storage rates and market structure for a three-year term, commencing January 1, 2005; and provides a gas transmission and storage revenue requirement of $428.5 million for 2005 (as compared to an authorized revenue requirement of $ 427.8 million for 2004), $436.6 million for 2006, and $444.9 million for 2007. 

D.  Annual Electric Rate True-Up

Also, on December 16, 2004, the CPUC approved the Utility’s first annual electric rate true-up to adjust rates for over- and undercollections in the Utility’s major electricity balancing accounts (including the Utility’s electricity procurement cost balancing account), establish the 2005 revenue requirement to amortize the regulatory asset established under the Settlement Agreement, and consolidate other CPUC and Federal Energy Regulatory Commission (FERC)authorized electric revenue requirement changes that are also effective on January 1, 2005, including the changes authorized in the cost of capital proceeding.  It is expected that these rate changes will result in an increase in 2005 electric revenues of approximately $300 million.  Additional rate changes will be made in the future to reflect the issuance of energy recovery bonds to refinance the regulatory asset established under the Settlement Agreement, as well as to reflect the outcome of other regulatory proceedings.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned thereunto duly authorized.

	PG&E CORPORATION
	By:	CHRISTOPHER P. JOHNS
		Christopher P. Johns Senior Vice President and Controller
	PACIFIC GAS AND ELECTRIC COMPANY
	By:	DINYAR B. MISTRY
		Dinyar B. Mistry Vice President and Controller

Dated:  December 21, 2004