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 30, 2005 (Date of earliest event reported)
PG&E CORPORATION
(Exact Name of Registrant as specified in Charter)
California	1-12609		94-3234914
(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))

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Item 1.01 – Entry Into a Material Definitive Agreement

Amendment to Pacific Gas and Electric Company Credit Agreement

               On November 30, 2005, Pacific Gas and Electric Company (Utility), a subsidiary of PG&E Corporation, entered into an amendment to its $1 billion revolving credit facility with Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Chase Bank, N.A., as syndication agent and a lender, Barclays Bank PLC and BNP Paribas as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and the following other lenders: Deutsche Bank AG New York Branch, ABN Amro Bank N.V., Lehman Brothers Bank, FSB, Mellon Bank, N.A., Royal Bank of Canada, The Bank of New York, UBS Loan Finance LLC, Union Bank of California, N.A., KBC Bank, N.V., Morgan Stanley Bank and William Street Commitment Corporation.  The amended credit facility will be used for working capital purposes. 

               The amendment increases the amount of the Utility’s revolving credit facility by $350 million to a total of $1.35 billion.  The amendment also increases the existing $600 million sublimit for the issuance of letters of credit by $350 million to $950 million but does not change the existing $100 million sublimit for swingline loans, i.e., loans made available on a same day basis and repayable in full within 30 days.  Under the amended credit facility, the Utility will pay reduced fees and interest rate spreads, which will vary depending on the Utility's unsecured debt rating by Standard & Poor’s Ratings Services (S&P) and Moody’s Investors Service (Moody’s).  If the Utility's debt ratings from S&P and Moody's are at different levels, the higher rating applies.  A facility fee is based on the total amount of the working capital facility (regardless of the usage) and a utilization fee is based on the average daily amount outstanding under the working capital facility.  The utilization fee is payable during any quarter in which the average daily amount outstanding under the working capital facility is in excess of 50% of the aggregate amount of the facility.  At the Utility's option, any loan under the working capital facility (other than swingline loans) bears interest at a rate equal to the "applicable margin" plus one of the following indexes: (i) LIBOR (London Interbank Overnight Rate) or (ii) the base rate (the higher of (a) the administrative agent's base rate and (b) the Federal Funds rate plus 0.50%).  

                The amended credit facility amends and restates the pricing grid as follows:

                The lenders and agents under the amendment to the Utility’s credit agreement and their affiliates have in the past provided, and may in the future provide, investment banking, underwriting, lending, commercial banking and other advisory services to the Utility and PG&E Corporation.  These parties have received, and may in the future receive, customary compensation from the Utility and PG&E Corporation for such services. 

Item 2.03 – Creation of a Direct Financial Obligation or an Obligation under an Off-Balance Sheet Arrangement of a Registrant

                The information set forth above in Item 1.01 regarding the amendment of the Utility’s revolving credit facility is hereby incorporated into Item 2.03(a) by reference.

Item 8.01 Other Events

2007 General Rate Case  

               On December 2, 2005, the Utility filed its 2007 General Rate Case (GRC) application with the California Public Utilities Commission (CPUC).  In the 2007 GRC, the CPUC will determine the amount of authorized base revenues to be collected from customers to recover the Utility's basic business and operational costs for its gas and electric distribution and existing electric generation operations for the period 2007 through 2009.  These revenue requirements are determined based on a forecast of costs for 2007 (the "test year").  

               In its application, the Utility has requested:

• an increase in electric and gas distribution revenue requirements of $481 million and $114 million, respectively, over the authorized 2006 revenue requirements to maintain current service levels to support increased investment in distribution infrastructure as plant in service is upgraded and replaced, and to adjust for wages and inflation. 
• an increase of $87 million, over the authorized 2006 revenue requirement, to cover increases in operational costs for the Utility's fossil, hydro, and nuclear generation facilities and administrative costs associated with electric procurement activities.
• attrition increases of $186 million for 2008 and $242 million for 2009 designed to avoid a reduction in earnings in years between GRCs that would otherwise occur because of increases in rate base and expenses. 

The authorized 2006 revenue requirements referred to above consist of the 2005 authorized revenue requirements plus authorized attrition revenue increases of $131 million for electric and gas distribution, and $35 million for electric generation.  The 2006 authorized revenue requirement will be included in the Utility’s annual electricity rate true-up filing supplement to be filed with the CPUC in late December 2005 and will be reflected in rates beginning January 1, 2006.

               Unlike the Utility’s August 1, 2005 Notice of Intent (NOI), the final GRC application includes a request for approval of pension contributions of $344 million per year in 2007, 2008 and 2009, and seeks an annual revenue requirement of $216 million to fund the portion of each year's pension contribution attributable to the Utility’s distribution and generation businesses.  The Utility included this request because the CPUC has not yet issued a final decision on the Utility’s July 2005 petition for permission to file a separate application to resume pension contributions beginning in 2006.  The petition estimated that the associated revenue requirement would be approximately $185 million per year over the 2006-2009 period.  The ultimate amount of the pension contribution request is subject to the CPUC’s final decision on the Utility’s July 2005 petition.  Aside from the added pension contribution request, the GRC application's revenue requirement request is $21 million lower than the NOI's as a net result of numerous minor revisions and corrections to forecasts.

               In the GRC application, the Utility also has proposed to reduce the 2008 and 2009 total gas and electric revenue requirements that it has otherwise requested by $41 million in 2008 and $97 million in 2009 to capture an estimate of net savings that the Utility anticipates may be realized from the operating and cost efficiencies achieved through implementation of specific initiatives identified by the Utility to provide better, faster and more cost-effective service to its customers.  Due to uncertainty about savings to be realized from these initiatives, the Utility has proposed a sharing mechanism in its GRC application by which shareholders and customers would share equally in any earnings over the amount needed to achieve a return on equity (ROE) equal to the then-authorized ROE plus 50 basis points.  The Utility’s customers would receive 100% of the earnings over the amount needed to achieve an ROE equal to the then-authorized ROE plus 3.00%.  If the Utility's actual ROE were less than an amount equal to the then-authorized ROE minus 50 basis points, shareholders and customers would share the shortfall equally.  The following table summarizes the proposed sharing mechanism based on the Utility's currently authorized ROE of 11.22%:

                In addition, the Utility’s GRC application includes a proposal to replace the current incentive mechanism for reliability performance for the 2007-2009 period with a new customer service performance incentive mechanism.  Under the proposal, the Utility would be rewarded or penalized up to $60 million per year (increased from the current maximum of $24 million per year) to the extent that the Utility’s actual performance exceeds or falls short of pre-set annual performance improvement targets over the 2007-2009 period.   The Utility has proposed to expand the areas of performance to be measured to include the following: generation availability (the amount of generating capacity capable of generating power over time, with reduction due to both planned and unplanned outages), timeliness of bills, telephone service level, average outage time over a one-year period (known as the system average interruption duration index, or SAIDI), average number of sustained outages over a one-year period (known as the system average interruption frequency index, and SAIFI), and how accurately the Utility provides outage information and estimates of power restoration.  

              It is anticipated that the administrative law judge overseeing the 2007 GRC will set a schedule to determine the expected dates for hearings, the issuance of a proposed decision, the issuance of a final decision, and other procedural events.  A final decision is expected from the CPUC by the end of 2006.

               PG&E Corporation and the Utility are unable to predict what amount of revenue requirements the CPUC will authorize for the 2007 through 2009 period, when a final decision in the GRC will be received, or what the impact of a final GRC decision will be on their financial condition or results of operations. 

Diablo Canyon Nuclear Power Plant 

               As previously disclosed, at the projected level of operation for the Utility’s two nuclear facilities at the Diablo Canyon nuclear power plant (Diablo Canyon), the Utility's current facilities are able to store on-site all spent nuclear fuel produced through approximately 2007.  On November 21, 2005, the Utility received a license issued by the Nuclear Regulatory Commission (NRC) authorizing the Utility to install a temporary storage rack in each unit's existing spent fuel storage pool that would permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011.  The Utility anticipates that it would complete the installation of the temporary storage racks by December 2006.  The Utility is waiting for the U.S. Court of Appeals for the Ninth Circuit to issue a decision on the appeal filed by several interveners challenging the NRC's March 2004 decision to authorize the Utility to operate a dry cask storage facility at Diablo Canyon to store spent nuclear fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2.  A decision is anticipated in late 2005 or the first quarter of 2006.  Construction of the on-site dry cask storage facility began in the third quarter of 2005 and is expected to be completed by 2008.  If the Utility is unable to complete the dry cask storage facility, or if construction is delayed beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operation of Diablo Canyon may have to be curtailed or halted as early as 2010 with respect to Unit 1 and 2011 with respect to Unit 2 and until such time as additional spent fuel can be safely stored.  If electricity from Diablo Canyon were unavailable, the Utility would be required to purchase electricity from other more expensive sources to meet its customers' demand. 

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
		LINDA Y.H. CHENG
		Linda Y.H. Cheng Vice President and Corporate Secretary
		PACIFIC GAS AND ELECTRIC COMPANY
		LINDA Y.H. CHENG
		Linda Y.H. Cheng Vice President and Corporate Secretary

Dated:  December 2, 2005