`UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
Date of Report: November 22, 2004
PG&E CORPORATION
(Exact Name of Registrant as specified in Charter)
California	1-2609		94-323914
(State or other jurisdiction of incorporation)	(Commission File Number)		(IRS Employer Identification No.)
One Market, Spear Tower, Suite 2400, San Francisco, CA		94105
(Address of principal executive offices)		(Zip code)
415-267-7000
(Registrant’s Telephone Number, Including Area Code)
N/A
(Former Name or Former Address, if Changed Since Last Report)
PACIFIC GAS AND ELECTRIC COMPANY
(Exact Name of Registrant as specified in Charter)
California	1-2348		94-0742640
(State or other jurisdiction of incorporation)	(Commission File Number)		(IRS Employer Identification No.)
77 Beale Street, P. O. Box 770000, San Francisco, California				94177
(Address of principal executive offices)				(Zip code)
(415) 973-7000
(Registrant’s Telephone Number, Including Area Code)
N/A
(Former Name or Former Address, if Changed Since Last Report)
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

[ ]	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 8.01 Other Events

A.  Proposed Decisions in Pacific Gas and Electric Company’s (Utility) Cost of Capital Proceeding

               On November 16, 2004, a proposed decision was issued by an administrative law judge overseeing the California investor-owned electric utilities' (IOUs) cost of capital proceedings at the California Public Utilities Commission (CPUC).  The CPUC Commissioner assigned to the proceedings also issued an alternate proposed decision (Alternate PD).  Both the proposed decision and the Alternate PD would approve the Utility’s request to recover (1) its actual cost of long-term debt and preferred stock from January 1, 2004 through April 11, 2004, and (2) its new cost of long-term debt and preferred stock resulting from its Chapter 11 exit financing that became effective on April 12, 2004, including hedging costs.  Both the proposed decision and the Alternate PD also would approve a return on common equity (ROE) for 2004 and 2005 of 11.22%,  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 Utility had requested a ROE of 11.60% for 2005.

               The proposed decision and the Alternate PD would authorize the following cost of capital for 2004 and 2005:

	2004			2005
		Capital	Weighted		Capital	Weighted
	Cost	Structure	Cost	Cost	Structure	Cost
Long-term debt	5.90%	48.2%	2.84%	6.10%	45.5%	2.78%
Preferred Stock	6.76%	2.8%	0.19%	6.42%	2.5%	0.16%
Common equity	11.22%	49.0%	5.50%	11.22%	52.0%	5.83%
Return on rate base			8.53%			8.77%

                If the proposed decision or the Alternate PD were adopted, the Utility’s annual revenue requirement for 2004 would decrease 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.  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% (resulting from its lower interest costs) requested in its cost of capital application.

                The Utility has proposed to include any electric revenue requirement change authorized in this proceeding in rates effective January 1, 2005.  The proposed decision and the Alternate PD would adopt the Utility’s proposal to include any gas revenue requirement changes authorized in this proceeding in the next gas transportation rate change, annual true-up or the biennial cost allocation proceeding.

                Both the proposed decision and the Alternate PD recognize the importance of assessing and mitigating the debt equivalence impacts on the 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 both proposed decisions decline to adopt a formal debt equivalence policy, they recommend 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 Alternate PD states that it would endorse a goal of "maintaining the major utilities' debt to capital, interest coverage, and cash flow to debt credit ratios to be no lower than the top third of S&P's BBB benchmarks for those credit ratios."   If the Alternate PD is adopted, it is possible that this ordering paragraph could be interpreted as a commitment by the CPUC to provide rate relief to enable the IOUs to maintain these credit ratios.  The ordering paragraph also may be interpreted to require the IOUs to maintain these credit ratios without regard to the level of rates approved by the CPUC.  The Utility will file comments on the Alternate PD seeking clarification of this issue.

                 Comments to the proposed decisions are due on December 6, 2004 and reply comments are due on December 13, 2004.  It is expected that the CPUC will issue a final decision by the end of the year.

B.  Proposed Decision on Long-Term Electricity Resource Plans

               On November 16, 2004, a proposed decision also was issued on the long-term electricity resource plans submitted to the CPUC by the IOUs to meet electricity resource adequacy requirements over the 10-year period 2004-2014.  In general, the proposed decision would adopt, with modifications, the IOUs’ long-term electricity resource plans (LTPs), would find that the LTPs are reasonable for planning purposes, and that the medium, preferred case scenarios in the LTPs should be followed for making planning and procurement decisions.  The proposed decision includes the following key points:

• The proposed decision would find 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 proposed decision notes that the Utility’s commitments may need to be increased or expedited for the Utility to meet its 2006 resource adequacy obligations.

• Rather than permit the Utility to have a pre-defined procurement target of 50% utility-owned generation resources and 50% contracted-for generation resources, as proposed by the Utility, the proposed decision would require that all the IOUs conduct a transparent and competitive solicitation through an RFO process from all potential sources of generation (e.g. conventional/renewable – turnkey power plants, buyouts, and PPAs) to meet their resource requirements.   In evaluating bids, the IOUs would be 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 “carbon 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 carbon adder would be used for analytical purposes only and would not be paid to a generator). 

When evaluating PPA bids, the IOU would be 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 proposed decision would reduce the factor to 10% in recognition of the improving California regulatory climate and the desire not to disadvantage PPAs unduly over utility-owned generation, particularly with respect to renewable generation.    As described above in the description of the proposed decisions in the cost of capital proceedings, the CPUC would consider the debt equivalence impact of PPAs on the IOUs' credit ratings, and therefore their costs of borrowing, in their future cost of capital proceedings.

• The proposed decision would prohibit IOUs from recovering costs in excess of their final bid price for utility-owned generation resources, stating that cost overruns should be borne by shareholders to level the playing field for IOU-owned generation projects and PPAs, with respect to risk allocation.

• The proposed decision would permit affiliates of the IOUs to participate in the bidding process for long-term PPAs, subject to certain guidelines and safeguards, including a requirement that the IOUs use an independent third party evaluator in resource solicitations where there are affiliates, IOU-built, or IOU-turnkey power plant bidders. 

• The proposed decision would permit the IOUs to recover their net stranded costs of all new fossil-fuel and renewable resources from all customers for a period of 10 years, including through the use of an exit fee, recognizing 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 proposed decision states that the IOUs would be 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 proposed decision would accept the Utility’s request to extend the mandatory rate adjustment mechanism under California Assembly Bill 57 (AB 57), which requires the CPUC 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 California Department of Water Resources (DWR).  Although AB 57 provides that these mandatory adjustments will cease on January 1, 2006, the Utility had requested that the CPUC extend the mandatory rate adjustment mechanism through at least the 10-year period covered by the Utility’s LTP.  The proposed decision would extend the time period during which the mandatory rate adjustment mechanism would be made to the length of a resource commitment or 10 years, whichever is longer.

• The proposed decision would deny 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.

• With respect to the IOUs’ contracting authority, the proposed decision would permit 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 three years or longer are submitted to the CPUC for pre-approval.  The proposed decision would adopt 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 proposed 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.

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

                 Comments are due on December 6, 2004 and reply comments are due on December 13, 2004.  It is expected that the CPUC will issue a final decision by the end of the year.

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

                Also, on November 16, 2004, a proposed decision was issued recommending approval of the Gas Accord III Settlement Agreement.  If approved by the CPUC, the final decision will:

• resolve all issues in this proceeding;

• set the Utility’s gas transmission and storage rates and market structure for a three-year term, commencing January 1, 2005; and

• provide 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.

                Assuming the CPUC issues a final decision by the end of the year, new rates would be effective on January 1, 2005.

D.  Redemption of Senior Notes

                On November 15, 2004, PG&E Corporation’s 6⅞% Senior Secured Notes due July 15, 2008 (Senior Secured Notes) were redeemed and the security interest in approximately 94% of the outstanding common stock of the Utility that is owned by PG&E Corporation that secured the Senior Secured Notes was released.  PG&E Corporation paid approximately $664.5 million, which included a redemption premium of approximately $50.7 million and $13.8 million of interest that has accrued since the last interest payment date, to redeem the Senior Secured Notes.  As a result of the Senior Secured Note redemption, PG&E Corporation will write off $14.3 million of unamortized loan fees.

E.  Credit Ratings

                On November 16, 2004, Fitch Ratings raised the Utility’s senior secured rating to BBB+ (from BBB) and initiated a rating of BBB+ on the Utility’s $850 million secured credit facility, raised the Utility’s indicative senior unsecured rating to BBB+ (from BBB-), and changed the outlook to stable (from positive) as a result of the upgrades.  Fitch Ratings stated that its ratings and stable outlook reflect what it considers to be the Utility’s manageable post-bankruptcy restructuring debt load and relatively stable cash flow outlook as well as the recent $600 million debt reduction at PG&E Corporation.

F.  Draft Resolution Regarding Billing Issues

                On November 16, 2004, a draft resolution was released for comment by the Energy Division of the CPUC.  The Energy Division’s draft resolution proposes to clarify the conditions under which the Utility can back-bill a residential customer for periods longer than three months.  The draft resolution was issued in response to the Utility’s advice letter filed with the CPUC on October 15, 2004 to implement a request from the Executive Director of the CPUC to discontinue collection of overdue amounts from residential customers that relate to charges for usage in excess of three months.  The draft resolution would accept the Utility’s proposal to change the applicable tariff language to provide that the failure to issue an actual or estimated bill is a “billing error.”  In the case of a “billing error,” a residential customer’s exposure is limited to three months for undercharges.  The Utility’s letter stated that the tariff changes it proposed would not affect customers’ billing obligations for bills issued before the proposed October 13, 2004 effective date. 

                The Utility Reform Network (TURN) filed a protest to the Utility’s advice letter.  TURN stated that the CPUC should reject the advice letter and instead review the Utility’s billing practices comprehensively in a new proceeding.  On November 9, 2004, TURN filed a motion requesting the CPUC to open an investigation into the Utility’s billing practices.  The Utility’s response to TURN’s motion is due on December 3, 2004.  The Energy Division’s draft resolution would deny TURN’s request to reject the advice letter outright, but would accept TURN’s request to reject the Utility’s suggestion to exempt from the definition of “billing error” circumstances where the failure to issue a bill was due to causes beyond the Utility’s reasonable control.  Instead, the Energy Division’s draft resolution would treat the failure to deliver a timely bill as a “billing error” except in situations where a customer had failed to establish service with the Utility.  The draft resolution would also treat the issuance of estimated bills as “billing error” and subject to the three month retroactive adjustment limitation except where the estimated bills result from the Utility’s inability to access the meter or other causes within the control of the customer.  In addition, the draft resolution would prevent the Utility from recovering charges for unauthorized use from the person who caused the unauthorized use.  Finally, the Energy Division’s draft resolution declares that the changes stated are “declarative of existing CPUC tariffs and requirements” and therefore would be retroactive to bills issued before October 13, 2004, as well as to bills issued prospectively.  

                 PG&E Corporation and the Utility believe that the draft resolution, if adopted as an order by the CPUC, would be unlawful to the extent it is applied retroactively to bills issued before October 13, 2004 and to the extent it would require the Utility to make tariff modifications beyond those it requested.   The issues addressed in the Energy Division’s draft resolution exceed the changes proposed by the Utility in its advice letter and have not been the subject of any hearing or other CPUC rulemaking process.

                 In releasing the draft resolution, the Energy Division indicated that the CPUC may vote on whether to adopt the draft resolution as early as its meeting to be held on December 16, 2004.  Comments on the draft resolution are due December 3, 2004 with reply comments due December 8, 2004.  Neither PG&E Corporation nor the Utility can predict the outcome of this matter.  It is possible that the outcome would have a material adverse effect on PG&E Corporation’s or the Utility’s results of operations or financial condition.

G. Approval of Energy Recovery Bond Application

                On November 19, 2004, the CPUC voted to approve the Utility's application for a wholly owned subsidiary to issue energy recovery bonds (ERBs) to refinance the remaining unamortized balance of the regulatory asset authorized under the Settlement Agreement (Settlement Regulatory Asset) and related federal income and state franchise taxes, in an aggregate principal amount of up to $3.0 billion in two separate tranches up to one year apart, to be secured by a dedicated rate component. (The dedicated rate component was authorized in June 2004 when California Senate Bill 772 became law.)  The decision authorizes the issuance of ERBs subject to the Utility’s consent to the terms and conditions of the CPUC’s financing order and approval of transaction terms by a financing team comprised of CPUC staff and their outside advisors. 

The remaining conditions to be met before ERBs can be issued are:

• The rating agencies determine that the issuance of ERBs will not adversely affect the Utility’s issuer or debt credit ratings, and

• The Utility obtains, or decides it does not need, a private letter ruling from the Internal Revenue Service (IRS) confirming that neither the refinancing of the Settlement Regulatory Asset nor the issuance of the ERBs is a presently taxable event.  On June 8, 2004, the Utility filed a request for a private letter ruling with the IRS. 

                 Assuming the timely satisfaction of these remaining conditions, the issuance of the first series of ERBs, in the amount of the after-tax balance of the Settlement Regulatory Asset (estimated to be approximately $1.8 billion), is targeted to occur in January 2005.

  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:	LINDA Y.H. CHENG
	Linda Y.H. Cheng Corporate Secretary
PACIFIC GAS AND ELECTRIC COMPANY
By:	LINDA Y.H. CHENG
	Linda Y.H. Cheng Corporate Secretary

Dated:  November 22, 2004