Pacific Gas & Electric (PCG)

Item 8.01 - Other Events

Litigation involving California Attorney General and the City and County of San Francisco

               On January 10, 2006, the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit) issued a 2-1 decision regarding the jurisdiction of certain claims for restitution brought by the California Attorney General (AG) and the City and County of San Francisco (CCSF) against PG&E Corporation.  PG&E Corporation disagrees with the Ninth Circuit’s decision and intends to file a petition for rehearing en banc.  The Ninth Circuit did not address the AG’s and CCSF’s underlying allegations that PG&E Corporation and the other defendants violated Section 17200 of the California Business and Professions Code.  PG&E Corporation believes these allegations have no merit, and that the ultimate outcome of this matter would not result in a material adverse effect on its financial condition or results of operations. 

                The Ninth Circuit ruled that the restitution claims were incorrectly removed from the jurisdiction of the San Francisco Superior Court (Superior Court), where they were originally filed in early 2002, to the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court) where the Utility’s Chapter 11 case was pending.  It is anticipated that the AG and CCSF will reassert their restitution claims in Superior Court. The Ninth Circuit decision reverses an earlier ruling by the U.S. District Court for the Northern District of California (District Court) that had determined that because the restitution claims are the property of the Utility's Chapter 11 estate, they belong within the Bankruptcy Court's jurisdiction.  The Ninth Circuit did not decide the issue of who would be entitled to receive the proceeds, if any, of a restitution award, and PG&E Corporation continues to believe that any such proceeds would be the property of the Utility. The settlement agreement approved by the Bankruptcy Court in the Utility’s Chapter 11 case provides that all claims by the California Public Utilities Commission (CPUC) against PG&E Corporation or the Utility arising out of or in any way related to the energy crisis are released, including the CPUC’s investigation into past PG&E Corporation actions during the energy crisis. Accordingly, PG&E Corporation believes that any claims for such proceeds by the CPUC would be precluded.

               The AG alleges that the defendants violated Section 17200 by violating various conditions established by the CPUC in decisions approving the formation of holding companies, including the so-called “first priority condition.”  The AG filed the complaint on January 10, 2002, the day after the CPUC issued a decision re-interpreting this condition more broadly than it had been interpreted in the previous 15 years.  The AG alleges that past transfers of funds from the Utility to PG&E Corporation during the period 1997 through 2000 (primarily in the form of dividends and stock repurchases), and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated these conditions.  The AG also argues that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis in 2000 and 2001.  After the AG’s lawsuit was filed, CCSF also filed a lawsuit with similar claims.  The Superior Court retained jurisdiction of the AG's and CCSF's civil penalty claims associated with the alleged Section 17200 violations.

               PG&E Corporation believes that the challenged intercompany transactions were in full compliance with applicable law and CPUC conditions.  The challenged transactions forming the bulk of the restitution claims were regular quarterly dividends and stock repurchases.  As part of its annual cost of capital proceedings, the Utility advised the CPUC in advance of its forecast stock repurchases and dividends.  The CPUC did not challenge or question those payments.  PG&E Corporation will continue to vigorously respond to and defend against the litigation. 

Dated: January 12, 2006

Item 8.01 Other Events

A.  PG&E Corporation Common Stock Dividend

              On December 21, 2005, the PG&E Corporation Board of Directors declared a quarterly common stock dividend of $0.33 per share, reflecting the increased annual dividend target of $1.32 that was approved by the Board on October 19, 2005.  The new dividend is consistent with the previously approved dividend policy and dividend payout ratio range (the proportion of earnings paid out as dividends) of 50 percent to 70 percent.  The Board of Directors retains authority to change its common stock dividend policy and its dividend payout ratio at any time, especially if unexpected events occur that would change the Board's views as to the prudent level of cash conservation.  The dividend is payable on January 16, 2006 to shareholders of record on December 30, 2005.

B.  2006 Cost of Capital Proceeding

               On December 15, 2005, the California Public Utilities Commission (CPUC) voted to issue a decision in the Utility’s cost of capital proceeding to determine the Utility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base for 2006.  (The Utility’s rate of return for its electric transmission operations is set by the Federal Energy Regulatory Commission (FERC) and the Utility’s rate of return for its gas transmission and storage operations through 2007 has been previously set in the Gas Accord settlement agreement approved by the CPUC.) 

               The decision establishes the following capital structure and rates of return for 2006, as compared to the 2005 authorized amounts:

                The Utility's authorized cost of capital would increase the 2006 cost of capital revenue requirement by approximately $4 million over the currently authorized revenue requirement for electricity and natural gas distribution and electricity generation operations, based on the Utility's currently authorized rate base.  

C.  Pension Contribution Application

              Also, on December 15, 2005, the CPUC approved in part the Utility’s July 2005 petition regarding resumption of pension contributions, giving the Utility permission to (1) file an application for a pension contribution in 2006, and (2) begin collecting the requested revenue requirement through rates effective January 1, 2006, subject to refund depending on the outcome of the application.    On December 20, 2005, the Utility filed the pension contribution application, requesting that the CPUC approve a net pension contribution of approximately $250 million in 2006, and the associated revenue requirement of $155 million attributable to  electric and gas distribution and generation operations. This annual net pension contribution amount of $250 million is the contribution level projected over a four year period (2006-2009) to increase the funded status of the pension plan trust from 98.6 percent on January 1, 2005, to 100 percent on January 1, 2010.  The requested revenue requirement of $155 million is less than the annual pension contribution amount because (1) a substantial portion of the annual pension contribution amount will be capitalized and (2) it does not include approximately $20 million in revenue requirements associated with natural gas transportation and storage, electric transmission, and nuclear decommissioning, which are the subject of other CPUC and FERC proceedings.  

D.  Annual Electricity Rate Adjustment

              Also, on December 15, 2005, the CPUC issued a resolution approving the Utility’s annual electric rate true-up filing that adjusts rates effective January 1, 2006 to (1) reflect over- and under- collections in the Utility's major electric balancing accounts (including electricity procurement), and (2) consolidate various other 2006 electricity revenue requirement changes authorized by the CPUC or the FERC during 2005 in other proceedings.  These rate changes, to be included in electricity rates on January 1, 2006, will increase electricity revenues by approximately $691 million as compared to revenues at present rates.  Balances in all accounts authorized for recovery by the December 15, 2005 resolution are subject to review, verification, and adjustment, if necessary, by the CPUC.

E.  Pending CPUC Investigation into the Utility’s Billing and Collection Practices

               As previously disclosed, the schedule in the CPUC’s pending investigation into the Utility's billing and collection practices called for the CPUC’s Consumer Protection and Safety Division (CPSD) and any other interested party to file their reports regarding the Utility’s practices by December 16, 2005.  On December 16, 2005, the CPSD requested an extension.  A telephone conference will be held on January 3, 2006, at which it is expected that a new due date for the CPSD’s and other parties' reports will be determined.  It is anticipated that the CPSD and The Utility Reform Network will submit reports that may recommend that the Utility be required to make refunds and pay penalties if the CPUC finds that the Utility violated applicable tariffs or the CPUC's orders or rules. 

               PG&E Corporation and the Utility continue to believe that the ultimate outcome of this matter will not have a material adverse effect on PG&E Corporation's or the Utility's financial condition or results of operations.

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. 

Dated:  December 2, 2005

Item 8.01 - Other Events

Diablo Canyon Steam Generator Replacement Projects

               On November 18, 2005, the California Public Utilities Commission (CPUC) voted to approve Pacific Gas and Electric Company's (Utility) application to replace the turbines, steam generators and other equipment at the two nuclear operating units at the Utility's Diablo Canyon nuclear power plant, referred to as the Steam Generator Replacement Project (SGRP).  The CPUC also certified the environmental impact report (EIR) with respect to the SGRP as final.  The EIR found that, for the SGRP as a whole, there are no environmental impacts that are significant, provided certain mitigation measures are implemented.

               In voting to approve its final decision, the CPUC adopted the findings it made in its February 24, 2005 interim decision that the SGRP is cost-effective, that the Utility’s projected cost of $706 million (as adjusted for actual inflation and cost of capital) is a reasonable estimate of the SGRP cost, and that the Utility cannot recover costs in excess of $815 million (as adjusted for actual inflation and cost of capital).  The CPUC also adopted its earlier findings that (i) if the costs did not exceed $706 million, the CPUC did not intend to conduct an after-the-fact reasonableness review of the SGRP costs but that such a review was not precluded, and (ii) if the cost exceeds $706 million (as adjusted for actual inflation and cost of capital) or the CPUC later finds that it has reason to believe the costs may be unreasonable regardless of the amount, the entire SGRP cost will be subject to a reasonableness review. 

               The majority of the projected capital costs for the SGRP will be expended over the 2007-2009 period as the Utility plans to replace the steam generators in Unit 2 in 2008 and in Unit 1 in 2009.

Dated:  November 18, 2005

Item 8.01 Other Events

            On November 9, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company which is wholly owned and consolidated by the Utility, issued its second series of energy recovery bonds, or ERBs, in the amount of $844,461,000.  (The first series of ERBs was issued on February 10, 2005 in the approximate amount of $1.9 billion.)  The second series of ERBs was issued in three classes, with scheduled maturities ranging from June 25, 2009 to December 25, 2012, and final legal maturities ranging from June 25, 2011 to December 25, 2014.  Interest rates on the three classes range from 4.85% for the earliest maturing class to 5.12% for the latest maturing class.  Repayment of principal and interest on each series of  ERBs is secured by a “recovery property” which includes the right to be paid a specified amount from a dedicated rate component, or DRC, that is collected by the Utility, acting as servicer, from electricity customers as a nonbypassable charge.  The Utility remits DRC charges to PERF to enable PERF to pay the principal and interest on the ERBs.  The proceeds of each series of ERBs, net of issuance costs, were used by PERF to purchase separate recovery property from the Utility. 

            The sale of the recovery property to PERF relating to the issuance of the second series of ERBs represents a pre-funding of the Utility's tax liability that will be due as the Utility collects the DRC from its customers over the term of the first and second series of ERBs.  Until these taxes are fully paid, the Utility will provide customers a carrying cost credit, computed at the Utility's authorized rate of return on rate base, to compensate customers for the use of the ERB proceeds.   It is estimated that the carrying cost credit will be approximately $125 million in 2006.  The equity portion of this carrying cost credit, approximately $55 million, will reduce 2006 net income.  The carrying cost credit and the resulting reduction to net income will decline as the taxes are paid, reaching zero in 2012 when the ERBs and related taxes are expected to be paid in full.

            While PERF is a wholly owned consolidated subsidiary of the Utility, PERF is legally separate from the Utility.  The assets of PERF (including the recovery property) are not available to creditors of the Utility or PG&E Corporation and the recovery property is not legally an asset of the Utility or PG&E Corporation. 

Dated:  November 9, 2005

Item 8.01 Other Events

Explanatory Note:

             On October 28, 2005, PG&E Corporation and Pacific Gas and Electric Company (Utility) filed a joint Current Report on Form 8-K (Report) that is being amended to restate in its entirety the text appearing under Item 8.01 as set forth below.  No other changes are being made to the Report or to the exhibits filed or furnished with the Report.  

Reclassification of Restricted Cash

             As previously disclosed in PG&E Corporation and Pacific Gas and Electric Company’s (Utility) joint quarterly report on Form 10-Q for the quarter ended June 30, 2005, PG&E Corporation and the Utility changed the way they classify changes in certain restricted cash balances presented in their condensed consolidated statements of cash flows for the reported quarterly period to present such changes as an investing activity.  These changes in restricted cash balances were previously presented as an operating activity.

             Exhibit 99.1 attached hereto consists of  Exhibit 13 (portions of PG&E Corporation’s and the Utility’s 2004 Annual Report to Shareholders) to their joint Annual Report on Form 10-K for the year ended December 31, 2004 (2004 Form 10-K), including the financial statements, the notes thereto, and the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that have been revised to reflect the Utility’s reclassification of changes in certain restricted cash balances as an investing activity rather than an operating activity for the years ended December 31, 2004, 2003 and 2002.  This reclassification also changes one of the financial statement schedules included with the 2004 Form 10-K.  This revised financial statement schedule, Condensed Financial Information of Parent, is attached as Exhibit 99.2.  In addition, attached hereto as Exhibit 99.3 is PG&E Corporation’s and the Utility’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2005 (First Quarter 2005 Form 10-Q) that has been revised to reflect the Utility’s reclassification of changes in certain restricted cash balances as an investing activity rather than an operating activity for the three months ended March 31, 2005.  There was no impact on PG&E Corporation’s or the Utility’s consolidated statements of operations, or shareholders’ equity as a result of these changes. 

             Except as described above, no other changes have been made to the portions of the Annual Report to Shareholders included as Exhibit 13 to the 2004 Form 10-K and no other changes have been made to the First Quarter 2005 Form 10-Q.   The attached Exhibits 99.1, 99.2, and 99.3 do not update any other disclosures to reflect developments since the 2004 Form 10-K or the First Quarter 2005 Form 10-Q were filed.

             PG&E Corporation and the Utility are filing this report at this time in light of the anticipated issuance of the second series of energy recovery bonds by PG&E Energy Recovery Funding LLC, or PERF, in November 2005.  Although PERF is a wholly owned and consolidated subsidiary of the Utility, the assets of PERF are not legally available to creditors of PG&E Corporation or the Utility, and neither PG&E Corporation nor the Utility are liable for the debts of PERF. 

Dated:  October 31, 2005

Item 8.01 Other Events

Reclassification of Restricted Cash

As previously disclosed in PG&E Corporation and the Pacific Gas and Electric Company’s (Utility) joint quarterly report on Form 10-Q for the quarter ended June 30, 2005, PG&E Corporation and the Utility changed the way they classify changes in certain restricted cash balances presented in their condensed consolidated statements of cash flows for the reported quarterly period to present such changes as an investing activity.  These changes in restricted cash balances were previously presented as an operating activity.

Exhibit 99.1 attached hereto consists of  Exhibit 13 (portions of PG&E Corporation’s and the Utility’s 2004 Annual Report to Shareholders) to their joint Annual Report on Form 10-K for the year ended December 31, 2004 (2004 Form 10-K), including the financial statements, the notes thereto, and the section entitled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” that have been revised to reflect the Utility’s reclassification of changes in certain restricted cash balances as an investing activity rather than an operating activity for the years ended December 31, 2004, 2003 and 2002.   This reclassification also changes one of the financial statement schedules included with the 2004 Form 10-K.  This revised financial statement schedule, Condensed Financial Information of Parent, is attached as Exhibit 99.2.  In addition, attached hereto as Exhibit 99.3 is PG&E Corporation’s and the Utility’s quarterly report on Form 10-Q for the quarter ended March 31, 2005 (First Quarter 2005 Form 10-Q) that has been revised to reflect the Utility’s reclassification of changes in certain restricted cash balances as an investing activity rather than an operating activity for the three months ended March 31, 2005.  There was no impact on PG&E Corporation’s or the Utility’s consolidated statements of operation or shareholders’ equity as a result of these changes.

Except as described above, no other changes have been made to the portions of the Annual Report to Shareholders included as Exhibit 13 to the 2004 Form 10-K and no other changes have been made to the First Quarter 2005 Form 10-Q.   The attached Exhibits 99.1, 99.2, and 99.3 do not update any other disclosures to reflect developments since the 2004 Form 10-K or the First Quarter 2005 Form 10-Q were filed.

The information appearing under the sections entitled “Item 9A.  Controls and Procedures” in Part II of the 2004 Form 10-K and under “Item 4.  Controls and Procedures” in Part I of the First Quarter 2005 Form 10-Q is hereby incorporated by reference into this report.

PG&E Corporation and the Utility are filing this report at this time in light of the anticipated issuance of the second series of energy recovery bonds by PG&E Energy Recovery Funding LLC, or PERF, in November 2005. Although PERF is a wholly owned and consolidated subsidiary of the Utility, the assets of PERF are not legally available to creditors of PG&E Corporation or the Utility, and neither PG&E Corporation nor the Utility are liable for the debts of PERF.

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Item 8.01 Other Events 

A.  PG&E Corporation Dividends

                On October 19, 2005, the PG&E Corporation Board of Directors approved an annual cash dividend target of $1.32 per share ($0.33 quarterly), an increase from the previously approved target of $1.20 per share that reflects the improved financial performance of PG&E Corporation, but balances the forecast level of Utility capital investments.  The new target is consistent with the previously approved dividend policy and dividend payout ratio range (the proportion of earnings paid out as dividends) of 50 percent to 70 percent.  The Board of Directors retains authority to change its common stock dividend policy and its dividend payout ratio at any time, especially if unexpected events occur that would change the Board's views as to the prudent level of cash conservation.  No dividend is payable until declared by the Board of Directors.  The Board of Directors expects to declare a quarterly common stock dividend of $0.33 per share based on the new target at its meeting in December 2005. 

B.  Authorized Share Repurchases

                PG&E Corporation previously disclosed that (i) it anticipated it would use cash received from the Utility to repurchase a total of $1.8 billion of PG&E Corporation common stock in 2005, (ii)  its Board of Directors  had authorized the repurchase of shares in an aggregate amount of  $1.05 billion, and (iii) this authorization was used when PG&E Corporation entered into an accelerated share repurchase arrangement on March 4, 2005. 

                On October 19, 2005, the Board of Directors of PG&E Corporation authorized the repurchase of up to $1.6 billion of common stock, from time to time, but no later than December 31, 2006 (although the actual repurchase or activity under the repurchase arrangements may occur after that date).  The repurchases may be made directly by PG&E Corporation, or through one or more subsidiaries, through brokers and dealers on the New York Stock Exchange and/or the Pacific Exchange or in privately negotiated transactions, which may include accelerated or forward or similar stock purchase programs or the issuance of puts or similar instruments and/or the establishment of one or more “Rule 10b5-1 plans.”  The maximum aggregate purchase price of $1.6 billion excludes brokers’ commissions and any gains or losses incurred in connection with hedging the risk associated with changes in the market price of PG&E Corporation’s common stock or the settlement of outstanding liabilities with respect to repurchased shares in connection with any accelerated share repurchase program or forward or similar stock purchase programs and any amounts paid in connection with puts or similar vehicles, the exercise of which may result in such purchases.   Such repurchases are contingent on PG&E Corporation’s receipt of sufficient cash from the Utility.

                As previously disclosed, for 2005, PG&E Corporation anticipates that it would receive at least $750 million from the Utility as payment for the repurchase of the Utility’s common stock.  To make this payment, the Utility plans to use some of the proceeds the Utility anticipates receiving from the second series of Energy Recovery Bonds (ERBs) expected to be issued in November 2005, and additional cash on hand in excess of the Utility’s liquidity needs and anticipated capital expenditures.   (The actual amount of proceeds received by the Utility from the second series of ERBs will depend upon the amount of generator refunds received in cash by the Utility before issuance of the ERBs.)

               Also, as previously disclosed, for 2006, PG&E Corporation anticipates utilizing any cash, in excess of its operational and capital investment needs and  liquidity targets, to repurchase shares.  Such amounts could be up to $200 million.  In addition, PG&E Corporation receives cash through the exercise of employee stock options.   PG&E Corporation may use such cash, anticipated to total approximately $300 million to $400 million for 2005 and 2006, to repurchase additional shares.

                It is expected that shares repurchased with cash received through the exercise of stock options would partially offset the number of shares issued pursuant to the exercise of those options, resulting in a minimal impact to the number of shares outstanding and the calculation of earnings per share.   Any additional stock repurchases made by PG&E Corporation in 2005 would not materially affect the average number of shares outstanding for purposes of calculating 2005 earnings per share.   

               The statements made in this report about anticipated stock repurchases constitute forward-looking statements that are necessarily subject to various risks and uncertainties and actual results may differ materially.  The ultimate amount of stock repurchased by PG&E Corporation in 2005 and 2006 will be affected by, among other factors, the amount of proceeds received by the Utility from the second series of ERBs, as discussed above, changes to PG&E Corporation’s and the Utility’s liquidity needs, actual cash from the Utility’s operations, the level of employee stock option exercises, and the actual level of the Utility’s capital expenditures.

Item 8.01 Other Events 

            On October 3, 2005, PG&E Corporation’s subsidiary, Pacific Gas and Electric Company (Utility), received a ruling issued by the Superior Court for the County of Los Angeles (Superior Court) granting one of the Utility’s pre-trial motions in litigation brought against the Utility by plaintiffs who allege that exposure to chromium at or near certain of the Utility’s natural gas compressor stations caused personal injuries, wrongful deaths, or other injuries (the “Chromium Litigation”).  As a result of the ruling, the Superior Court dismissed one plaintiff who was scheduled to participate in the first trial who claimed that chromium caused her Crohn’s disease.  The ruling also applies to seven other plaintiffs who are claiming that exposure to chromium caused them to contract Crohn’s disease.  Also, on September 20, 2005, in response to another pre-trial motion that had been filed by the Utility, three plaintiffs who were scheduled to participate in the first trial voluntarily dismissed their claims.  These pre-trial motions challenged the plaintiffs' lack of admissible scientific evidence that chromium caused the alleged injuries.  However, as disclosed in PG&E Corporation’s and the Utility’s most recent joint Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 (Form 10-Q), the Superior Court has denied other pre-trial motions made by the Utility and also has denied the Utility’s motions for reconsideration of the denials. 

            In light of these denials, PG&E Corporation and the Utility stated in their most recent Form 10-Q that they were no longer able to predict whether the ultimate outcome of the Chromium Litigation would have a material adverse impact on their financial condition or results of operations.  Previously, PG&E Corporation and the Utility had been able to conclude that they believed that the ultimate outcome, after taking into account the $160 million already reserved for the Chromium Litigation, would not have a material adverse impact on PG&E Corporation's or the Utility's financial condition or results of operations.  The dismissals entered on September 20 and the October 3 ruling have not altered this assessment of the ultimate outcome of the Chromium Litigation. 

            There are currently about 1,200 plaintiffs in the Chromium Litigation who seek compensatory damages, more than 1,000 of whom are also seeking punitive damages.  Although the plaintiffs’ complaints in the Chromium Litigation do not state the amount of compensatory or punitive damages claimed, approximately 1,000 of the current plaintiffs filed claims in the Utility's Chapter 11 case requesting compensatory damages in an approximate aggregate amount of $500 million and others filed claims for an "unknown amount."  (The Utility’s exit from Chapter 11 in April 2004 did not affect the plaintiffs’ claims for compensatory and punitive damages.)

            The Utility has sought appellate court review of the Superior Court's denials of the Utility's earlier pre-trial motions based on the argument that they are inconsistent with recent California appellate decisions (one of which is now under review by the California Supreme Court) concerning the admissibility of expert testimony and the requirements for proving medical causation.  The appellate court ordered the plaintiffs to file a brief addressing the issues raised by the Utility.  Plaintiffs' brief was filed on September 23, 2005 and the Utility's responses were filed on September 30 and October 3, 2005.  The appellate court's decision as to whether to consider the merits of the Utility's appeal is still pending.

            The trial for the 14 remaining plaintiffs who were selected to participate in the first trial is scheduled to begin on January 9, 2006.  Counsel for the Utility and counsel for the plaintiffs are engaged in settlement discussions.  PG&E Corporation and the Utility cannot predict the outcome of these discussions.

Dated:  October 7, 2005

Item 8.01 Other Events

               On September 22, 2005, the California Public Utilities Commission (CPUC) voted to approve the Utility’s application to spend up to $49 million on pre-deployment activities to implement an advanced metering infrastructure for residential and small commercial customers.  The CPUC authorized the Utility to recover from customers up to $11.7 million in pre-deployment expenses and $37.4 million in pre-deployment capital additions.  The pre-deployment phase consists of activities to prepare the Utility’s existing systems to accept data from its proposed advanced metering system, and to establish and test processes for meter and communication system installation and billing.  The authorized pre-deployment funding translates into combined electric and gas distribution revenue requirements of approximately $13.8 million in 2005, $6.3 million in 2006, and $6.2 million in 2007. 

               As previously reported, in a separate proceeding in June 2005, the Utility filed with the CPUC an application for deployment of its full advanced metering infrastructure project at an estimated cost of $1.46 billion, including an estimated capital cost of $1.26 billion, based on a five-year installation schedule for virtually all of the Utility's electric and gas customers starting in 2006.  A final CPUC decision is expected in May 2006.  PG&E Corporation and the Utility cannot predict whether the CPUC will approve this application.

Dated:  September 22, 2005

Item 8.01 - Other Events

First Mortgage Bonds

             In March 2004, the Utility issued $6.7 billion aggregate principal amount of First Mortgage Bonds secured by a lien on substantially all of the Utility’s real property and certain tangible personal property related to the Utility’s facilities.  First Mortgage Bonds in the aggregate amount of $2.5 billion also were used to secure the Utility's obligations under various agreements.  The governing indenture provided that the lien could be released when, among other conditions, Moody's Investors Service (Moody’s) and Standard & Poor’s Rating Service (S&P) provided written evidence that the ratings on the Utility's long-term unsecured debt obligations immediately after the lien was released would be at least equal to the initial ratings on the First Mortgage Bonds (BBB by S&P and Baa2 by Moody’s).  Moody’s and S&P have confirmed that the bonds would be rated BBB by S&P and Baa1 by Moody’s (as increased by Moody’s from Baa2 on March 3, 2005) after release of the lien.  On April 22, 2005, the Utility and The Bank of New York Trust Company, N.A., the successor to BNY Western Trust Company, as trustee, amended and restated the indenture to eliminate the provisions related to the lien of the mortgage.  There is no longer any collateral securing the bonds and the bonds have become the Utility's unsecured general obligations, ranking equally with the Utility's other unsecured debt.  The Utility has agreed that it will not incur secured debt except for (1) debt secured by specified liens, and (2) secured debt in an amount not exceeding 10% of the Utility's tangible net assets, as defined in the indenture.

In addition, the designations of the remaining $5.3 billion in aggregate principal amount of First Mortgage Bonds have been changed as follows: 

            The Committee on Uniform Securities Identification Procedures (CUSIP) numbers of these instruments remain the same. Certain other bonds outstanding under the indenture, which had been used to support the Utility’s repayment obligations under credit facilities and certain of the pollution control loan agreements, have been cancelled.

Tax-Exempt Financing

            On April 20, 2005, the Utility repaid $454 million under certain reimbursement obligations that the Utility entered into in April 2004 when its plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code became effective.  These reimbursement obligations replaced the Utility’s obligation to certain issuers of letters of credit whose letters of credit were drawn upon during the Chapter 11 proceeding in connection with the  redemption of certain pollution control bonds that had been issued for the benefit of the Utility.  The Utility drew $454 million under its $1 billion credit agreement to repay the reimbursement obligations.  The Utility anticipates that this draw will be repaid with the proceeds of a future tax-exempt financing through the issuance of bonds by a state agency for the benefit of the Utility.  The Utility passes on to its customers interest cost savings attributable to the lower interest rates associated with such tax-exempt financing. 

            On April 22, 2005, the Utility entered into an amendment of four reimbursement agreements totaling $620 million related to letters of credit aggregating $614 million that had been issued to support certain pollution control bonds issued on behalf of the Utility.  In addition to reducing pricing and generally conforming the covenants and events of default to those in the $1 billion working capital facility, the term of the amended agreements has been extended from three years to five years, until April 22, 2010.

Redemption of Preferred Stock

            On April 20, 2005, the Utility’s Board of Directors authorized the redemption of all of the outstanding shares of the Utility’s 6.57% Redeemable First Preferred Stock, CUSIP No. 694308 69 3 (6.57% Preferred Stock) and 6.30% Redeemable First Preferred Stock, CUSIP No. 694308 65 1 (6.30% Preferred Stock), totaling approximately $120 million aggregate par value.  Both issues will be redeemed on May 31, 2005.  In addition to the $25 per share redemption price, holders of the 6.57% Preferred Stock and the 6.30% Preferred Stock will be entitled to receive an amount equal to all accumulated and unpaid dividends on such shares to and including May 31, 2005.

Item 8.01 - Other Events

Annual Earnings Assessment Proceedings

            On April 4, 2005, the Utility filed a motion with the California Public Utilities Commission (CPUC) seeking approval of a settlement agreement entered into on April 4, 2005 between the Utility and the CPUC’s Office of Ratepayer Advocates (ORA).  The settlement agreement proposes the resolution of the Utility’s claims that have been pending for several years for shareholder incentives earned by the Utility for the successful implementation of demand-side management, energy efficiency, and low-income energy efficiency programs for past program years (1994 through 2001).  The Utility’s claims for shareholder incentives are addressed in the Utility’s Annual Earnings Assessment Proceeding (AEAP).  In addition to resolving claims made in the pending AEAPs, the settlement agreement proposes to resolve all future claims for shareholder incentives relating to past program years that the Utility would otherwise have made in future AEAPs through 2010. 

            The Utility’s total current and future shareholder incentive claims aggregate to approximately $207 million.  Under the settlement agreement, the parties have agreed that the results to date show that the energy savings anticipated in the Utility’s shareholder incentive claims are being realized.  The parties have proposed that the Utility receive shareholder incentives of approximately $186 million to resolve the Utility’s claims in the pending and future AEAPs.   The parties have proposed that approximately $160 million be allocated to electric customers, and that the remaining $26 million be allocated to gas customers, in proportion to the relative allocations of the original claims. 

            PG&E Corporation and the Utility cannot predict whether or when the CPUC will approve the settlement agreement.  Assuming the CPUC approves the settlement agreement, the Utility would record pre-tax income of $186 million during the quarter in which the settlement agreement is approved by the CPUC.   The Utility has already collected $28 million of the $186 million from electric customers through the public goods charge.  It is anticipated that the remaining $158 million would be collected from customers over a 12-month period beginning on January 1, 2006, assuming prior CPUC approval of the settlement agreement. 

Dated:  April 11, 2005

Item 8.01 - Other Events

A.  Dismissal of City of Palo Alto’s Appeal of the Confirmation Order 

On March 21, 2005, the City of Palo Alto (City) filed a stipulation in the U.S. District Court for the Northern District of California requesting the court to enter an order of voluntary dismissal of the City’s appeal of the December 22, 2003 order of the U.S. Bankruptcy Court for the Northern District of California that confirmed Pacific Gas and Electric Company’s (Utility) plan of reorganization under Chapter 11 of the U.S. Bankruptcy Code.  It is expected that the court will enter an order of dismissal pursuant to the stipulation. 

With respect to the appeal of the confirmation order filed by two former commissioners of the California Public Utilities Commission (CPUC) with the U.S. Court of Appeals for the Ninth Circuit, the Utility's answering brief is due April 25, 2005.  The Utility intends to argue that the appeal should be dismissed because it became moot after the CPUC commissioners’ terms expired on December 31, 2004 and because the former CPUC commissioners lack standing to pursue the appeal.

B.   December 2003 Mission Street Substation Fire

On March 22, 2005, the Utility received a copy of an order issued by the CPUC dated March 17, 2005, that institutes an investigation into the circumstances surrounding a fire that occurred at the Utility’s Mission Street substation in San Francisco on December 20, 2003 and the ensuing power outage.  The CPUC ordered the Utility to show cause why the CPUC should not impose fines and sanctions on the Utility related to the Mission Street substation fire and outage.  The order states that "[b]ased on the public reports of both PG&E and CPSD [the CPUC’s Consumer Protection and Safety Division], there is good cause to find that PG&E violated Public Utilities Code section 451 by failing to maintain its system in a safe and reliable manner."  In its report to the CPUC regarding the December 20, 2003 outage, the Utility acknowledged that after the 1996 fire it did not adequately consider two measures that had been identified to minimize the effect of a fire at the Mission Street substation.  The Utility acknowledged that if it had implemented those measures, its response to the 2003 fire would have been faster, although the fire would not have been prevented.   The CPUC emphasized that the Utility did not take action following a similar fire at the substation in 1996 and states that "[w]e place PG&E on notice that it must demonstrate why it should not be held liable for allowing an unsafe condition to exist during the time period after the 1996 fire when PG&E was warned of the danger at the Mission substation by its own engineers." 

In addition, on March 28, 2005, the CPUC issued a press release noting that CPUC staff also would investigate the causes of a fire and power outage that originated at the Mission Street substation on March 26, 2005 that affected about 23,500 of the Utility’s customers. 

The CPUC’s March 22, 2005 order notes that the CPUC has authority to impose penalties in the amount of $500 to $20,000 per day per offense for violations of the Public Utilities Code.  The order states that the CPUC may consider a penalty for each customer that lost power, or for each day the outage was ongoing.  Approximately 100,000 customers were affected by the December 20, 2003 outage, which began in the early evening of December 20, 2003.  While most customers had their power restored by the next morning, the outage lasted more than 24 hours for some customers.  In order to evaluate safety and reliability in the Utility’s substations system-wide, the CPUC requires the Utility to provide a status report to the CPSD by May 17, 2005 describing the condition of, and the safety enhancements made at, the Utility’s other indoor substations since 1996.  If the CPUC finds that the Utility’s maintenance and/or operations practices at other indoor substations are unsafe, unreasonable, improper, or insufficient, it may order the Utility to change or improve its maintenance, operations, or construction standards for substations to ensure system-wide safety and reliability.

The Utility has paid approximately $2.5 million to resolve claims stemming from the December 2003 outage.

The Utility and the CPSD made a combined total of 38 recommendations in their 2004 reports.  Many of these recommendations suggested that the Utility take certain actions, such as adding or replacing equipment, at the Mission Street substation, and evaluate taking similar actions at other indoor substations.  The Utility is taking steps to carry out the recommendations.

PG&E Corporation and the Utility are unable to predict whether the outcome of this matter will have a material adverse effect on their results of operation or financial condition.

After a CPUC administrative law judge (ALJ) is assigned to the investigation, a prehearing conference will be held to set a schedule.

C.  Delayed and Estimated Bills

Also, on March 22, 2005, a CPUC ALJ presiding over the CPUC’s investigation into the Utility’s billing and collection practices that has been opened at the request of The Utility Reform Network (TURN), considered the following schedule in the proceeding:

As previously disclosed, on January 13, 2005, the CPUC adopted a resolution approving tariff changes stating that "billing error" includes failure to issue a bill and issuance of an estimated bill, under certain circumstances.  The resolution stated that the tariff changes approved by the resolution "are consistent with existing CPUC policy, tariffs, and requirements."   The CPUC also stated that failure to issue a bill or estimating a bill due to changes to a billing system should be treated as a billing error for purposes of applying the tariff prohibiting billing residential customers for more than 3 months usage.   On February 17, 2005, the Utility filed an application with the CPUC requesting rehearing of this resolution on the basis that the resolution's characterization of the revised "billing error" definition as consistent with "existing CPUC policy, tariffs, and requirements" is contrary to both the plain language of the Utility's prior tariffs and the CPUC's own policies and requirements interpreting the Utility's prior tariffs.   On February 25, 2005, TURN’s motion requesting an investigation was granted. 

In the case of "billing errors," the Utility is prohibited under its tariffs from billing residential customers for more than three months’ usage. The investigation will examine whether the Utility violated its tariffs by billing customers in excess of the three-month limitation.  The investigation will also evaluate the scope and impact of the Utility’s billing and collection practices on the Utility’s customers.  Among the issues to be considered are:

• the effect of the Utility’s new billing system, CorDaptix, (implemented in December 2002) on the Utility’s billing practices; and
• the Utility’s customer deposit requirements and collection practices since the beginning of 2002.

The average number of delayed bills over the five-year period 2000-2004 is below the Utility’s historic average for the period 1993 - 2004.  This five-year average corresponds to about 0.6 percent of the more than 5 million bills issued per month by the Utility.  In 1999, significant changes were made to the Utility’s billing system to “unbundle” the services for which rates were charged to accommodate direct access customers.  During the period following this system change delayed bills increased.  In December 2002, the Utility implemented its new billing and customer information system.    As  was expected and is typical for such a significant system change, the number of delayed and estimated bills increased, with estimated bills reaching a high shortly after conversion in early 2003 and delayed bills rising to a high in the summer of 2003.  Between 2003 and 2004, the number of delayed bills decreased significantly.  The annual average for 2004 was better than the historic 12-year average by 50 percent.  For January 2005, the Utility’s average of delayed bills reached an all-time low.

If the CPUC finds that the Utility violated applicable tariffs or the CPUC’s orders or rules, the CPUC may impose penalties on the Utility or order the Utility to refund any amounts collected in violation of tariffs, plus interest, to customers who paid such amounts.

PG&E Corporation and the Utility continue to believe that the ultimate outcome of this matter will not have a material adverse effect on PG&E Corporation's or the Utility's results of operations or financial condition.

Dated:  March 30, 2005