exv13


⁽¹⁾	Operating income (loss) and income (loss) from continuing operations reflect the write-off of generation-related regulatory assets and under-collected electricity purchase costs in 2000. See Management’s Discussion and Analysis of Financial Condition and Results of Operations and Notes to the Consolidated Financial Statements for discussion of matters relating to certain data.

PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, electricity transmission, and natural gas transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. PG&E Corporation also owns National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engages in electricity generation and natural gas transportation in the United States, or U.S.

The Utility served approximately 4.9 million electricity distribution customers and approximately 3.9 million natural gas distribution customers at December 31, 2003. The Utility had approximately $29.1 billion in assets at December 31, 2003 and generated revenues of approximately $10.4 billion in 2003. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

In 1996, California enacted Assembly Bill, or AB, 1890, which mandated the restructuring of the California electricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. As required by AB 1890, beginning January 1, 1997, electricity rates for all customers were frozen at the level in effect on June 10, 1996 and, beginning January 1, 1998, rates for residential customers were further reduced by 10%. The frozen rates were designed to allow the Utility to recover its authorized utility costs and, to the extent the frozen rates generated revenues greater than these costs, to recover the Utility’s costs stranded by the regulatory change, or transition costs.

AB 1890 also gave customers the choice of continuing to buy electricity from the California investor-owned electric utilities or, beginning in April 1998, purchasing electricity from an alternate energy provider. The customers that opted to purchase electricity from alternate energy service providers are known as direct access customers. The Utility bills direct access customers based on fully bundled rates that include electricity procurement, generation, distribution, transmission and other components. The Utility then gives direct access customers energy credits equal to the procurement component of the fully bundled rates, or direct access credits.

Beginning in May 2000, wholesale electricity prices began to increase so that the frozen rates were not sufficient to recover the Utility’s operating and electricity procurement costs. The Utility financed the higher costs of wholesale electricity by issuing debt in the fall of 2000 and drawing on its credit facilities. Ultimately, the inability of the Utility to recover its electricity procurement costs from its customers resulted in billions of dollars in defaulted debt and unpaid bills. On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. The Utility retained control of its assets and is authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding.

In January 2001, because of the deteriorating credit of the California investor-owned electric utilities, the State of California Department of Water Resources, or DWR, began purchasing electricity to meet each utility’s net open position, which is the portion of the demand of a utility’s customers, plus applicable reserve margins, not satisfied from that utility’s own generation facilities and existing electricity contracts. The DWR is legally and financially responsible for its electricity contracts. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power charge. These customers also must pay another revenue requirement, which is known as a bond charge, for the DWR’s costs associated with its $11.3 billion bond offering completed in November 2002. On January 1, 2003, each California investor-owned electric utility resumed purchasing electricity to meet the portion of its net open position not provided by the DWR contracts allocated to that utility’s customers, or that utility’s residual net open position.

In January 2001, the CPUC authorized the Utility to collect the first of three electricity surcharges intended to help it reduce the impact of the high wholesale electricity prices. The rate surcharges totaled $0.045 per kilowatt-hour, or kWh, and were fully implemented by June 2001.

In mid-2001, wholesale electricity prices moderated. As a result of these surcharges and moderating electricity prices, the Utility’s net income and cash balances increased. This has allowed the Utility to pay its post-petition operating expenses and other post-petition liabilities with internally generated funds. In addition, the Utility has paid interest on certain pre-petition liabilities and the principal of maturing mortgage bonds with bankruptcy court approval.

In September 2001, PG&E Corporation and the Utility proposed a plan of reorganization that would have disaggregated the Utility’s businesses. In April 2002, the CPUC, later joined by the Official Committee of Unsecured Creditors, proposed an alternate plan of reorganization that would not have disaggregated the Utility’s businesses. On December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into a settlement agreement, or the Settlement Agreement, that contemplated a new plan of reorganization, or the Plan of Reorganization, to supersede the competing plans. Under the Settlement Agreement, the Utility remains vertically integrated. On December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization, which fully incorporates the Settlement Agreement. The Plan of Reorganization provides that the Utility will pay all allowed creditor claims in full (except for the claims of holders of certain pollution control-related bond obligations that will be reinstated) from the proceeds of a public offering of long-term debt, cash on hand and draws on credit facilities. At December 31, 2003, allowed claims in the Utility’s Chapter 11 proceeding amounted to approximately $12.2 billion.

The Settlement Agreement permits the Utility to emerge from Chapter 11 as an investment grade entity by generally ensuring that the Utility will have the opportunity to collect in rates reasonable costs of providing its utility service. The Settlement Agreement provides that the Utility’s authorized return on equity will be no less than 11.22% per year and, except for 2004 and 2005, its authorized equity ratio will be no less than 52% until the Utility’s credit rating has increased to a specified level. The Settlement Agreement establishes a $2.21 billion after-tax regulatory asset and allows for the recognition of an approximately $800 million after-tax regulatory asset related to generation assets. The Settlement Agreement and related decisions by the CPUC provide that the Utility’s revenue requirement will be collected regardless of sales levels and that the Utility’s rates will be timely adjusted to accommodate changes in costs that the Utility incurs.

On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC Commissioners who did not vote to approve the Settlement Agreement and a municipality have appealed the bankruptcy court’s confirmation order in the U.S. District Court for the Northern District of California, or the District Court. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of the Plan of Reorganization until the appeals are resolved. The District Court will set a schedule for briefing and argument of the appeals at a later date. No additional parties may request rehearings or make appeals of the CPUC’s approval of the Settlement Agreement or the bankruptcy court’s confirmation order.

Implementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the debt securities provided for under the Plan of Reorganization) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, PG&E Corporation and the Utility do not believe that the applicable accounting probability standard needed to record the regulatory assets contemplated by the Settlement Agreement has been met. PG&E Corporation and the Utility believe that the Utility and the long-term debt to be issued will receive investment grade credit ratings. The Utility has targeted April 2004 to complete the sale of the long-term debt, which the Utility expects to be the last condition of the Plan of Reorganization to be satisfied. The Plan of Reorganization provides that the effective date will occur 11 business days after all the conditions have been satisfied or, with respect to all conditions except those relating to investment grade credit ratings, waived by PG&E Corporation and the Utility. There can be no assurance

In early January 2004, the CPUC issued a decision finding that the rate freeze mandated by AB 1890 ended on January 18, 2001. In mid-January 2004, the Utility entered into a rate design settlement agreement, or rate design settlement, with representatives of major customer groups that addresses revenue allocation and rate design issues associated with the decrease in the Utility’s revenue requirements resulting from the Settlement Agreement, DWR revenue requirements and other CPUC actions. On February 11, 2004, a proposed decision was issued that would adopt the rate design settlement with a modification for DWR revenues. This proposed decision, if approved by the CPUC, combined with the January 2004 CPUC decision regarding the rate freeze, provides that the Utility will no longer collect the frozen rates and surcharges. Instead, it will collect the regulatory assets arising from the Settlement Agreement, as amortized into rates, the revenue requirements established by the 2003 general rate case, or GRC, and revenue requirements established in other proceedings. The Utility has reached an agreement with several consumer groups to resolve its 2003 GRC, or GRC settlement, and set its electricity and natural gas revenue requirements and its electricity generation revenue requirement through 2006. The GRC settlement is pending CPUC approval. If the rate design settlement agreement is ultimately approved, the Utility’s electricity customers would receive an electricity rate reduction of approximately 8%, on average, in March 2004, or shortly thereafter, retroactive to January 1, 2004. The Utility expects that as a result of this rate reduction, electricity operating revenues would decrease by approximately $799 million compared to revenues generated at current rates. In addition, if the 2003 GRC settlement is not approved, the net average reduction in electricity rates and associated reduction in electricity operating revenue will be even greater.

The Utility’s results of operations will be affected by whether and when the Settlement Agreement and Plan of Reorganization are implemented. Other significant factors that affect the Utility’s results of operations include:


	•	CPUC decisions affecting the rates that the Utility can charge for its services and determining the costs that are allowable for recovery within the Utility’s rate structure;

	•	The amount and cost of electricity purchased;

	•	Other operating expenses; and

	•	The performance of distribution, generation, transmission and transportation operating assets.

The CPUC has broad influence over the operations of the Utility. The Utility’s revenue requirements are authorized primarily by the CPUC and the CPUC approves the rates that the Utility charges its customers. The CPUC is also responsible for setting service levels and certain operating practices. These decisions have a significant impact on the amount of costs the Utility incurs. The CPUC is responsible for reviewing the Utility’s capital and operating costs and in certain cases prescribes specific accounting treatment.

Electricity procurement costs historically have impacted the Utility’s results of operations and financial condition. California legislation has been enacted which allows the Utility to recover substantially all its prospective wholesale electricity procurement costs and requires the CPUC to adjust rates on a timely basis to ensure that the Utility recovers its costs. Accordingly, for 2004 and beyond, electricity procurement costs are not expected to have the same impact on the Utility’s results of operations that they had during the California energy crisis. However, the level of electricity procurement costs will continue to have an impact on cash flows.

Operating expenses are a key factor in determining whether the Utility earns the rate of return authorized by the CPUC. Many of the Utility’s costs, including electricity procurement costs, discussed above, are subject to ratemaking mechanisms that are intended to provide the Utility the opportunity to fully recover these costs. However, there is no ratemaking mechanism for recovery of the Utility’s operating and maintenance expenses. As a result, changes in the Utility’s operating expenses impact the Utility’s results of operations.

The Utility’s distribution, generation, transmission and transportation operating assets generally consist of long-lived assets with significant construction and maintenance costs. The Utility’s annual capital expenditures are expected to average approximately $1.7 billion annually over the next five years. A significant outage at any of these facilities may have a material impact on the Utility’s operations. Costs associated with replacement electricity and natural gas or use of alternative facilities during these outages could have an adverse impact on PG&E Corporation’s and the Utility’s results of operations and liquidity.

On July 8, 2003, NEGT filed a voluntary petition for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. The factors that caused NEGT to take this action are discussed further below and in Note 5 of the Notes to the Consolidated Financial Statements. In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives, who previously served as directors of NEGT, resigned on July 7, 2003 and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over NEGT. Accordingly, effective July 8, 2003, NEGT’s results are no longer consolidated with those of PG&E Corporation. NEGT’s results of operations through July 7, 2003 and for prior years have been reclassified as discontinued operations, and PG&E Corporation now accounts for its investment in NEGT using the cost method of accounting. PG&E Corporation’s net negative investment in NEGT at December 31, 2003 was approximately $1.2 billion.

NEGT’s future results are not expected to have a material adverse impact upon the financial condition or results of operations of PG&E Corporation or the Utility.

On February 2, 2004, NEGT filed a second amended plan of reorganization with the bankruptcy court that, when implemented, would eliminate PG&E Corporation’s equity interest in NEGT. If NEGT’s proposed plan of reorganization or another plan that eliminates PG&E Corporation’s equity in NEGT is implemented, PG&E Corporation will reverse its investment in NEGT and related amounts included in deferred income taxes and accumulated other comprehensive income and, as a result, recognize a material one-time net non-cash gain to earnings from discontinued operations.

The Consolidated Financial Statements of PG&E Corporation and the Utility have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and repayment of liabilities in the ordinary course of business.

This is a combined annual report of PG&E Corporation and the Utility and includes separate Consolidated Financial Statements for each of these two entities. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include the accounts of the Utility and its wholly owned and controlled subsidiaries. This combined Management’s Discussion and Analysis of Financial Condition and Results of Operations, or MD&A, should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in this report.

This combined Annual Report and the letter to shareholders that accompanies it contain forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on the information currently available to management. These forward-looking statements are identified by words such as “estimates,” “expects,” “anticipates,” “plans,” “believes,” “could,” “should,” “would,” “may” and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements.

Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:


	•	The timing and resolution of the pending applications for rehearing of the CPUC’s approval of the Settlement Agreement and any appeals that may be filed with respect to the disposition of the rehearing applications;

	•	The timing and resolution of the pending appeals of the bankruptcy court’s confirmation of the Plan of Reorganization;

	•	Whether the investment grade credit ratings and other conditions required to implement the Plan of Reorganization are obtained or satisfied; and

	•	Future equity and debt market conditions, future interest rates, and other factors that may affect the Utility’s ability to implement the Plan of Reorganization or affect the amounts and terms of the debt proposed to be issued under the Plan of Reorganization.


	•	Unanticipated changes in operating expenses or capital expenditures;

	•	The level and volatility of wholesale electricity and natural gas prices and supplies and the Utility’s ability to manage and respond to the levels and volatility successfully;

	•	Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility’s assets or operations or those of third parties on which the Utility relies;

	•	Unanticipated population growth or decline, changes in market demand and demographic patterns and general economic and financial market conditions, including unanticipated changes in interest or inflation rates;

	•	The extent to which the Utility’s residual net open position increases or decreases due to changes in customer and economic growth rates, the periodic expiration or termination of Utility or DWR power purchase contracts, the reallocation of DWR power purchase contracts, whether various counterparties are able to meet their obligations under their power sale agreements with the Utility or with the DWR, the retirement or other closure of the Utility’s electricity generation facilities, the performance of the Utility’s electricity generation facilities and other factors;

	•	The operation of the Utility’s Diablo Canyon nuclear power plant, which exposes the Utility to potentially significant environmental and capital expenditure outlays and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close its Diablo Canyon power plant and purchase electricity from more expensive sources;

	•	Actions of credit rating agencies;

	•	Significant changes in the Utility’s relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and

	•	Acts of terrorism.


	•	The impact of other current and future ratemaking actions of the CPUC, including the outcome of the Utility’s 2003 GRC;

	•	Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, U.S. Congress, the CPUC, the FERC and the Nuclear Regulatory Commission, or NRC, with regard to allowed rates of return, industry and rate structure, recovery


		of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;

	•	The extent to which the CPUC or the FERC delays or denies recovery of the Utility’s costs, including electricity purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons;

	•	How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC’s decisions permitting the establishment of holding companies for California investor-owned electric utilities;

	•	Whether the Utility is in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;

	•	Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations and policies; and

	•	The outcome of pending litigation.


	•	Increased competition as a result of the takeover by condemnation of the Utility’s distribution assets, duplication of the Utility’s distribution assets or service by local public utility districts, self-generation by its customers and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and

	•	The extent to which the Utility’s distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers and the extent to which cities, counties and others in the Utility’s service territory begin directly serving the Utility’s customers or combine to form community choice aggregators.

On December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into the Settlement Agreement and, on December 22, 2003, the bankruptcy court confirmed the Plan of Reorganization that fully incorporates the Settlement Agreement.

The principal terms of the Settlement Agreement that will affect the Utility’s results of operations and liquidity include:

Regulatory Assets. The Settlement Agreement establishes a $2.21 billion after-tax regulatory asset (which is equivalent to an approximately $3.7 billion pre-tax regulatory asset) as a new, separate and additional part of the Utility’s rate base to be amortized on a “mortgage-style” basis over nine years retroactive to January 1, 2004. Under this amortization methodology, annual after-tax collections of a $2.21 billion regulatory asset in electricity rates are estimated to range from approximately $140 million in 2004 to approximately $380 million in 2012, although these amounts will be reduced as discussed below. The unamortized balance of this after-tax regulatory asset will earn a rate of return on its equity component of no less than 11.22% annually for its nine-year term. The rate of return on this regulatory asset would be eliminated if the Utility completes the refinancing discussed below. Instead, the Utility would collect from customers amounts sufficient to service the securitized debt. The net after-tax amount of any refunds, claim offsets or other credits the Utility receives from energy suppliers related to specified electricity procurement costs incurred during the California energy crisis and arising from the settlement of CPUC litigation against El Paso Natural Gas Company, or El Paso, related to electricity refunds, but not natural gas refunds, will reduce the outstanding balance of this regulatory asset. In the rate design settlement pending before the CPUC, the reduction to the regulatory asset related to the El Paso Settlement and certain other generator refunds and claim offsets is stipulated to be $189 million, after-tax. The estimated amount will be subject to adjustment based on actual amounts received by the Utility. Additional refunds and claim offsets would further reduce this regulatory asset. Reductions of the regulatory asset reduce the amount amortized into rates.

In addition, as part of the Settlement Agreement, the CPUC will deem the Utility’s adopted 2003 electricity generation rate base of approximately $1.6 billion to be just and reasonable and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation would allow recognition of an approximately $800 million after-tax regulatory asset (which is equivalent to an approximately $1.3 billion pre-tax regulatory asset).

The Utility expects to recognize the pre-tax amounts of the two regulatory assets once the Utility determines in accordance with accounting principles generally accepted in the United States of America, or GAAP, that these regulatory assets are probable of recovery as discussed above. This recognition would increase PG&E Corporation’s and the Utility’s total assets by approximately $5.0 billion. It also will result in the recording of approximately $2.0 billion of deferred tax liabilities that would be recognized as income tax expense. In addition, the recognition of these regulatory assets and related deferred taxes will result in a one-time non-cash gain of approximately $3.0 billion of net income for the year of recognition, with a similar increase in PG&E Corporation’s and the Utility’s shareholders’ equity. All these amounts will be reduced for refunds, claim offsets and other credits received prior to the initial recognition of the regulatory assets in PG&E Corporation’s financial statements.

Ratemaking. Under the terms of the Settlement Agreement, the CPUC has agreed to act timely upon the Utility’s applications to collect in rates prudently incurred costs of any new, reasonable investment in utility plant and assets and has agreed to timely adjust the Utility’s rates to ensure that it collects in rates fixed amounts to service existing rate reduction bonds, regulatory asset amortization and return and base revenue requirements. In addition, the CPUC has agreed to set the Utility’s capital structure and authorized return on equity in its annual cost of capital proceedings in its usual manner. From January 1, 2004 until Moody’s Investors Service, or Moody’s, has issued an issuer rating for the Utility of not less than A3 or Standard & Poor’s, or S&P, has issued a long-term issuer credit rating for the Utility of not less than A-, the Utility’s authorized return on equity will be no less than 11.22% per year and its authorized equity ratio will be no less than 52%. However, for 2004 and 2005, the Utility’s authorized equity ratio will equal the greater of the proportion of equity approved in the Utility’s 2004 and 2005 cost of capital proceedings, or 48.6%.

The Settlement Agreement provides that the Utility’s retail electricity rates are to be maintained at their existing level through 2003. In 2004, the Utility will no longer collect the revenue generated by the frozen rates and surcharges that it collected in 2003, 2002 and 2001. Instead, it will collect revenues designed to recover the regulatory assets, as amortized into rates, and the revenue requirements established by the 2003 GRC and other regulatory proceedings. Although revenue requirements would increase over previously authorized amounts if the pending GRC settlement is approved by the CPUC, the elimination of the surcharges will result in a net average reduction of electricity rates effective March 2004, or shortly thereafter, retroactive to January 1, 2004. In addition, the Utility will recognize expenses related to the amortization of the regulatory assets in 2004 and beyond, expenses not present in 2003. The amortization of the regulatory assets would have no direct impact on cash flow because amortization is a non-cash expense. The decrease in rates will, however, reduce cash flow. Other than the one-time impact of recording net income associated with recognition of the regulatory assets discussed above, overall implementation of the Settlement Agreement and related rulemaking will decrease the Utility’s net income in 2004 as compared to 2003. In addition, if the GRC settlement is not approved, the amount of the rate reduction and revenue reduction will increase.

Securitization. PG&E Corporation and the Utility have agreed to seek to refinance up to a total of $3.0 billion of the unamortized pre-tax balance of the $2.21 billion after-tax regulatory asset, as expeditiously as practicable after the effective date of the Plan of Reorganization using a financing supported by a dedicated rate component, provided certain conditions are met. These conditions include the enactment of authorizing California legislation satisfactory to the CPUC, the Utility and The Utility Reform Network, or TURN, and that the securitization not adversely affect the Utility’s credit ratings. The Utility expects to use the securitization proceeds to rebalance its capital structure in order to maintain the capital structure provided in the Settlement Agreement.

After the securitization, the rate of return on the unamortized pre-tax balance of the $2.21 billion after-tax regulatory asset would be eliminated. Instead the Utility would collect from customers amounts sufficient to service the securitized debt. Electricity rates would be further reduced to reflect the lower cost of capital of the securitized financing, causing a corresponding decrease in the Utility’s net income.

The Plan of Reorganization provides for payment in full in cash of all allowed creditor claims (except for the claims of holders of approximately $814 million of pollution control bond-related obligations that will be reinstated), plus applicable interest on claims in certain classes, and all cumulative dividends in arrears and mandatory sinking fund payments associated with the Utility’s outstanding preferred stock. The following is a summary of all claims the Utility has recorded at December 31, 2003 (including all claims related to obligations that will be reinstated at the effective date of the Plan of Reorganization):

The Utility expects to pay all allowed claims (other than claims represented by reinstated obligations) on or as soon as practicable after the effective date of the Plan of Reorganization and to establish escrow accounts to pay disputed claims as they are resolved. The Utility expects that it will require approximately $11.0 billion in cash to pay the allowed claims (including a payment of approximately $310 million for maturing mortgage bonds to be made on March 1, 2004, pending approval of the bankruptcy court) and make the necessary escrow deposits. In addition, $814 million outstanding under the Pollution control loan agreements will be reinstated. The Utility expects to offset allowed power procurement claims with amounts owed to the Utility by the PX. This netting reduces the cash requirement of the plan by approximately $500 million.

The Utility expects to use approximately $2.8 billion of cash on hand, after retirement of the mortgage bonds, to pay allowed claims and make necessary escrow deposits. In accordance with the Plan of Reorganization, the balance of the cash requirements will be met with the proceeds of a public offering of approximately $7.4 billion of long-term debt and draws on various credit facilities.

On July 8, 2003 NEGT filed a voluntary petition for relief under Chapter 11. The decline in wholesale electricity prices, NEGT’s construction program, the decline of NEGT’s credit rating to below investment grade and lack of market liquidity created severe financial distress and ultimately caused it to seek protection under Chapter 11. In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives, who previously served as directors of NEGT, resigned on July 7, 2003 and were replaced with directors who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over NEGT. NEGT’s proposed plan of reorganization provides for the elimination of PG&E Corporation’s equity ownership. PG&E Corporation believes that the bankruptcy court will approve NEGT’s proposed plan of reorganization, or a plan with similar equity elimination provisions for PG&E Corporation.

As a result of NEGT’s Chapter 11 filing and the elimination of equity ownership provided for in NEGT’s proposed plan of reorganization, PG&E Corporation considers its investment in NEGT to be an abandoned asset and

has accounted for NEGT as discontinued operations in accordance with Statement of Financial Accounting Standards, or SFAS, No. 144, “Accounting for Impairment or Disposal of Long-Lived Assets,” or SFAS No. 144. Under the provisions of SFAS No. 144, the operating results of NEGT and its subsidiaries through July 7, 2003 and for all prior years are reported as discontinued operations in the Consolidated Statements of Operations. As of July 8, 2003, PG&E Corporation accounts for NEGT using the cost method and NEGT is no longer consolidated by PG&E Corporation for financial reporting purposes. The accompanying December 31, 2003 Consolidated Balance Sheet of PG&E Corporation does not reflect the separate assets and liabilities of NEGT; rather, a liability of approximately $1.2 billion is reflected, which represents the losses recognized by PG&E Corporation in excess of its investment in and advances to NEGT. PG&E Corporation’s investment in NEGT will not be affected by changes in NEGT’s future financial results.

When NEGT’s proposed plan of reorganization or another plan that eliminates PG&E Corporation’s equity interest in NEGT is implemented, PG&E Corporation will reverse its investment in NEGT and related amounts included in deferred income taxes and accumulated other comprehensive income and, as a result, recognize a material one-time net non-cash gain to earnings from discontinued operations.

NEGT and its creditors have filed a complaint against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT’s Board of Directors asserting, among other claims that NEGT is entitled to be compensated under an alleged tax-sharing agreement for any tax savings achieved by PG&E Corporation as a result of the incorporation of losses and deductions related to NEGT or its subsidiaries in PG&E Corporation’s consolidated federal income tax return. In May 2003, PG&E Corporation received $533 million from the Internal Revenue Service, or IRS, for an overpayment of 2002 estimated federal income taxes. NEGT and its creditors have asserted that they have a direct interest in certain tax savings achieved by PG&E Corporation and are entitled to be paid approximately $414 million of the funds received by PG&E Corporation (approximately $361.5 million achieved by the incorporation of losses and deductions related to NEGT or its subsidiaries and approximately $53 million achieved by the incorporation of certain tax credits related to one of NEGT’s subsidiaries). Consequently, until the dispute is resolved, PG&E Corporation is treating $361.5 million as restricted cash. PG&E Corporation anticipates continuing to incorporate losses, deductions and certain tax credits related to NEGT or its subsidiaries in PG&E Corporation’s consolidated federal tax return, until it is no longer consolidated for federal income tax purposes. NEGT and its creditors similarly assert that NEGT is entitled to be compensated for any tax savings resulting from inclusion of these losses in PG&E Corporation’s federal tax return. PG&E Corporation denies that any tax sharing agreement, whether implied or expressed, ever existed and denies that it has any obligation to compensate NEGT for the incorporation of losses and deductions related to NEGT or its subsidiaries into PG&E Corporation’s consolidated federal tax returns.

PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations, financial position or liquidity.

The table below details certain items from the accompanying Consolidated Statements of Operations for 2003, 2002 and 2001.


⁽¹⁾	Includes preferred dividend requirement as other expense.

⁽²⁾	PG&E Corporation eliminates all intersegment transactions in consolidation.

⁽³⁾	Operating results of NEGT have been reclassified as discontinued operations. See Note 5 of the Notes to the Consolidated Financial Statements.

The following presents the Utility’s operating results for 2003, 2002 and 2001. As described below, net income for 2003 reflects a decline in operating revenues compared to 2002 as a result of increases in the DWR’s revenue requirements and an increased cost of electricity because the Utility resumed procuring electricity to cover its residual net open position in 2003. Net income for 2002 reflects an increase in operating revenues compared to 2001 due to increased electricity surcharge collections and a decrease in amounts passed through to the DWR. Although the Utility is not able to predict all of the factors that may affect future results, results of operations in 2004 will be materially different from historical results if the Settlement Agreement is implemented, the CPUC approves the Utility’s 2003 GRC settlement, and the rate design settlement is implemented.

From mid-January 2001 through December 2002, the DWR was responsible for procuring electricity required to cover the Utility’s net open position. The Utility resumed purchasing electricity on the open market in January 2003 to satisfy its residual net open position, but still relies on electricity provided under DWR contracts for a material portion of its customers’ demand. Revenues collected on behalf of the DWR and the DWR’s related costs are not included in the Utility’s Consolidated Statements of Operations, reflecting the Utility’s role as a billing and collection agent for the DWR’s sales to the Utility’s customers. Under the frozen rate structure, increases in the revenues passed through to the DWR decreased the Utility’s revenues.

In January 2001, the CPUC authorized the Utility to collect an electricity surcharge, the first of three surcharges intended to help the California investor-owned electric utilities pay for the high cost of wholesale electricity. The surcharges, totaling $0.045 per kWh, were fully implemented by June 2001 and were collected through December 31, 2003, while frozen rates remained in place.

The following table shows a breakdown of the Utility’s electricity operating revenue by customer class:

In 2003, the Utility’s electricity operating revenues decreased approximately $596 million, or 7%, compared to 2002 mainly due to the following factors:


	•	Pass-through revenue to the DWR increased by approximately $187 million, or 9%, in 2003 from 2002. This increase was mainly due to an aggregate increase of $1.0 billion in DWR power and bond charges, partially offset by an approximately $444 million reduction in the 2003 DWR revenue requirement and an approximately $369 million adjustment recorded in the third quarter of 2002 to reflect required changes to the methodology used to calculate DWR pass-through revenues.


	The reduction in the DWR’s 2003 revenue requirement was mainly due to a September 2003 CPUC decision that reduced the DWR’s approved revenue requirement for 2003. The decision also required the Utility to pass the benefit of the revenue requirement reduction on to its customers through a one-time bill credit in 2003. As a result, the approximately $444 million


	reduction in the 2003 DWR revenue requirement was offset by a corresponding reduction in electricity operating revenues for each customer class in 2003.


	•	The Utility recorded a regulatory liability or reserve for the potential refund of approximately $125 million of surcharge revenues collected during 2003 as provided by the terms of the rate design settlement entered into in January 2004. The rate design settlement is subject to approval by the CPUC.

	•	Due to an April 2002 CPUC decision that increased baseline quantity allowances that was applied for all of 2003 but only a portion of 2002, electricity operating revenues decreased by an additional $44 million in 2003. An increase to a customer’s baseline quantity allowance increases the amount of the customer’s monthly usage that is covered under the lowest possible rate and is exempt from certain surcharges.

	•	The decrease in electricity operating revenues was partially offset by the collection of a cost responsibility surcharge, or CRS, a non-bypassable charge to direct access customers for their share of certain costs incurred by the Utility. The CPUC implemented this surcharge on January 1, 2003 and the Utility collected approximately $187 million in CRS revenues from direct access customers in 2003.

In 2002, the Utility’s electricity operating revenues increased approximately $852 million, or 12%, compared to 2001 mainly due to the following factors:


	•	The amount of CPUC authorized surcharges increased approximately $751 million, or 34%, in 2002 from 2001. This increase reflects the collection of $0.045 per kWh in surcharges for all of 2002 compared to the collection of $0.01 per kWh in surcharges for substantially all of 2001 and the remaining $0.035 per kWh in surcharges for only seven months during 2001.

	•	Direct access credits decreased approximately $176 million, or 38%, in 2002 from 2001 mainly due to a decrease in the average direct access credit per kWh, partially offset by an increase in the total electricity provided to direct access customers by alternate energy service providers. The average direct access credit per kWh was lower in 2002 than in 2001 because in the beginning of 2001 the Utility used the California Power Exchange, or PX, price for wholesale electricity to calculate direct access credits. After the PX closed in January 2001, direct access credits have been calculated based on the electricity procurement component of the fully bundled rate, which has been significantly lower than the PX price. The average direct access credit decreased from $0.116 per kWh in 2001 to $0.038 per kWh in 2002. In 2002, alternate energy service providers supplied approximately 7,433 Gigawatt-hours, or GWh, of electricity to direct access customers, compared to approximately 3,982 GWh in 2001.

	•	Revenue passed through to the DWR decreased by approximately $117 million, or 5%, in 2002 from 2001. This decrease was mainly due to a decrease in the Utility’s net open position, which resulted in less DWR electricity being delivered to the Utility’s customers. The decrease in the Utility’s net open position was caused by increases in the number of direct access customers and in the amount of electricity the Utility was able to purchase from qualifying facilities due to renegotiated payment terms. In addition, the Utility accrued approximately $369 million in additional pass through revenues to the DWR in 2002 due to changes proposed by the DWR to the methodology used to calculate DWR remittances. Absent this accrual, the decrease in the revenue passed through to the DWR would have been greater.

The Utility will no longer collect the frozen rates and surcharges that it collected in 2003, 2002 and 2001 after the implementation of the rate design settlement. Instead, revenues in 2004 will be based on an aggregation of individual rate components, including base revenue requirements, electricity procurement costs and the DWR revenue requirement, among others. Changes in the DWR revenue requirements will change rates charged to certain of the Utility’s customers. As a result, changes in amounts passed through to the DWR will no longer affect the Utility’s results of operations. A proposed decision has been issued adopting a settlement with representatives of major customer groups, which, if approved by the CPUC, will reduce electricity rates by approximately 8.0%, on average and result in a reduction of electricity operating revenues of approximately $799 million.

The Utility’s cost of electricity includes electricity purchase costs and the cost of fuel used by its owned generation facilities but it excludes costs to operate its generation facilities. The following table shows a breakdown of the Utility’s cost of electricity and the total amount and average cost of purchased power, excluding in each case both the cost and volume of electricity provided by the DWR to the Utility’s customers:

In 2003, the Utility’s cost of electricity increased approximately $837 million, or 56%, compared to 2002 mainly due to the following factors:


	•	The Utility’s total volume of electricity purchased in 2003 increased 31% because the Utility resumed buying and selling electricity on the open market beginning in the first quarter of 2003 to meet its residual net open position in accordance with its CPUC-approved electricity procurement plan.

	•	The increase in total costs was partially offset by proceeds from surplus electricity sales. The Utility is required to dispatch all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. This requirement, in certain cases, requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the open market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR based on the percentage of volume supplied by each entity to the Utility’s total load. The Utility’s net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.

	•	In March 2002, the Utility recorded a net reduction of approximately $595 million to the cost of electricity as a result of FERC and CPUC decisions that allowed the Utility to reverse previously accrued Independent System Operator, or ISO, charges and to adjust for the amount previously accrued as payable to the DWR for its 2001 revenue requirement. There was no comparable reduction in 2003.

In 2002, the Utility’s cost of electricity decreased approximately $1.3 billion, or 47%, compared to 2001 because the Utility’s average cost of purchased power decreased compared to 2001 mainly due to the significantly lower prices for electricity after the energy market stabilized in the second half of 2001. In addition, the DWR purchased all of the electricity needed to meet the Utility’s net open position for all of 2002, whereas in 2001 the Utility purchased the electricity itself through the PX market through the first half of January 2001.

In 2002, FERC and CPUC decisions allowed the Utility to reverse previously accrued ISO charges and adjust previously accrued DWR pass-through revenues, reducing the cost of electricity by a net of approximately $595 million. In 2001, the Utility recorded approximately $552 million for the market value of terminated bilateral contracts, reducing the cost of electricity by approximately $552 million for that year. The net effect of these adjustments contributed to an additional decrease of approximately $43 million in the cost of electricity in 2002.

The Utility’s cost of electricity in 2004 will be dependent upon electricity prices and the Utility’s residual net open position.

The following table shows a breakdown of the Utility’s natural gas operating revenues:

In 2003, the Utility’s total natural gas operating revenues increased approximately $520 million, or 22%, compared to 2002 mainly due to the following factors:


	•	Bundled natural gas revenues increased by approximately $552 million, or 27%, in 2003 from 2002 mainly due to a higher average cost of natural gas, which the Utility is permitted by the CPUC to pass on to its customers through higher rates. The average bundled revenue per thousand cubic feet, or Mcf, of natural gas sold in 2003 increased $2.06, or 29%, compared to 2002. Natural gas prices increased in 2003 mainly due to a shortage in natural gas supply and lower storage reserves.

	•	Transportation service-only revenues decreased by approximately $32 million, or 10%, in 2003 from 2002 mainly due to a decrease in demand for natural gas transportation services by certain non-core customers, mainly natural gas-fired electric generators in California. An increase in electricity available from hydroelectric facilities and the greater efficiency of generation facilities that commenced operations in 2003 resulted in reduced demand for natural gas transportation services.

In 2002, the Utility’s total natural gas operating revenues decreased approximately $800 million, or 26%, compared to 2001 mainly due to the following factors:


	•	Bundled natural gas revenues decreased by approximately $741 million, or 27%, in 2002 from 2001 mainly due to a lower average cost of natural gas. The average bundled revenue per Mcf of natural gas sold in 2002 decreased $3.03, or 30%, compared to 2001. Natural gas prices decreased in 2002 mainly due to an overall increase in natural gas supply and higher storage reserves.

	•	Transportation service-only revenue decreased by approximately $59 million, or 16%, in 2002 from 2001 mainly due to a decrease in demand for gas transportation services by natural gas-fired electric generators in California.

The Utility’s natural gas revenues in 2004 are expected to increase due to natural gas distribution rate increases in the GRC settlement and will be further impacted by changes in the cost of natural gas.

The Utility’s cost of natural gas includes the purchase cost of natural gas and transportation costs on interstate pipelines, but excludes the costs associated with its intrastate pipeline, which are included in operating and maintenance expense. The following table shows a breakdown of the Utility’s cost of natural gas:

In 2003, the Utility’s total cost of natural gas sold increased approximately $513 million, or 54%, compared to 2002 mainly due to the following factors:


	•	The Utility’s cost of natural gas sold increased approximately $483 million, or 57%, in 2003 from 2002 mainly due to an increase in the average cost of natural gas sold in 2003 of $1.77 per Mcf, or 59%.

	•	The Utility’s cost of natural gas transportation increased by approximately $30 million, or 30%, in 2003 from 2002 mainly due to pipeline transportation charges paid to El Paso. The Utility, along with other California utilities, was ordered by the CPUC in July 2002 to enter into new long-term contracts to purchase firm transportation services on the El Paso pipeline, under which the Utility pays a fixed amount to secure capacity on the El Paso pipeline.

In 2002, the Utility’s total cost of natural gas sold decreased approximately $878 million, or 48%, compared to 2001 mainly due to the following factors:


	•	The Utility’s cost of natural gas sold decreased by approximately $740 million, or 46%, in 2002 from 2001 mainly due to a decrease of $2.86 per Mcf, or 49%, in the average cost of natural gas sold.

	•	The Utility’s cost of natural gas transportation decreased by approximately $138 million, or 58%, in 2002 from 2001 mainly due to approximately $111 million in costs recognized in 2001 related to the involuntary termination of natural gas transportation hedges caused by a decline in the Utility’s credit rating. There were no similar events in 2002.

The Utility’s cost of natural gas sold in 2004 will be affected by the prevailing costs of natural gas, which are determined by North American regions that supply the Utility.

Operating and maintenance expenses consist mainly of the Utility’s costs to operate its electricity and natural gas facilities, maintenance expenses, customer accounts and service expenses, administrative and general expenses, and the net deferral of revenues and expenses based on the difference between certain revenues and expenses recognized under GAAP and those revenues and expenses recognized for regulatory purposes.

In 2003, the Utility’s operating and maintenance expenses increased approximately $118 million, or 4%, compared to 2002 mainly due to a reversal of a liability of approximately $65 million for surcharge revenues in excess of ongoing procurement costs and half-cent surcharge revenue collections at the end of 2002. The remainder of the increase was mainly due to wage increases in 2003 and increases in employee benefit plan-related expenses due to a 15% decrease in returns on plan investments and a decrease in the discount rates used to calculate the present value of the Utility’s benefit obligations from 6.75% to 6.25%.

These increases were partially offset by a net increase in deferred electricity transmission-related costs compared to 2002. Electricity transmission-related costs are included in the cost of electricity and consist mainly of charges imposed by the ISO for grid management services. To the extent the Utility does not receive revenues sufficient to recover electricity transmission-related costs, the costs are deferred through a reduction of operating and maintenance expense until recovered in rates.

In 2002, the Utility’s operating and maintenance expenses increased approximately $432 million, or 18%, compared to 2001 mainly due to the following factors:


	•	Employee benefit plan-related expenses increased approximately $115 million in 2002 from 2001 mainly due to a 7% decrease in returns on plan investments and lower interest rates, which caused a decrease in the discount rate used to calculate the present value of the Utility’s benefit obligations;

	•	Environmental related expenses increased approximately $54 million in 2002 from 2001 mainly due to an increase in third party liabilities;

	•	The Utility’s new customer billing system, which was implemented at the end of 2002, increased customer accounts and service expenses by approximately $23 million, or 9%, in 2002 from 2001. The increased cost in 2002 resulted from pre-implementation testing, validation and training costs;


	•	The net deferred electricity transmission-related costs increased approximately $142 million in 2002 from 2001; and

	•	The Utility began deferring over-collected electricity revenue associated with the rate reduction bonds in 2002. Total deferred revenue was approximately $85 million in 2002.

In 2003, the Utility’s depreciation, amortization and decommissioning expenses increased approximately $25 million, or 2%, compared to 2002 mainly due to an overall increase in the Utility’s plant assets.

In 2002, the Utility’s depreciation, amortization and decommissioning expenses increased approximately $297 million, or 33%, compared to 2001 mainly due to the amortization of approximately $290 million of the rate reduction bond regulatory asset that began in January 2002.

In accordance with the American Institute of Certified Public Accountants’ Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” or SOP 90-7, the Utility reports reorganization fees and expenses separately on its Consolidated Statements of Operations. These costs mainly include professional fees for services in connection with the Utility’s Chapter 11 proceedings and totaled approximately $160 million in 2003, $155 million in 2002 and $97 million in 2001. Upon implementation of the Plan of Reorganization and repayment in cash of substantially all allowed creditor claims and applicable interest and dividends, as discussed in the “Cash Requirements of the Plan of Reorganization” section above, the Utility will no longer incur reorganization fees and expenses.

In accordance with SOP 90-7, the Utility reports reorganization interest income separately on its Consolidated Statements of Operations. Reorganization interest income mainly includes interest earned on cash accumulated during the Utility’s Chapter 11 proceedings. Interest income, including reorganization interest income, decreased approximately $21 million, or 28%, in 2003 from 2002 and approximately $49 million, or 40%, in 2002 from 2001. Decreases for both periods were mainly due to lower average interest rates earned on the Utility’s short-term investments.

In 2003, the Utility’s interest expense decreased approximately $35 million, or 4%, compared to 2002 mainly due to the reduction in the amount of rate reduction bonds outstanding, reflecting the declining principal balance of the rate reduction bonds and a lower amount of unpaid debts accruing interest. This decrease was partially offset by the recording of approximately $38 million interest payable to the DWR in 2003 based upon a CPUC decision issued in January 2004. The interest payable to the DWR compensates the DWR for prior underpayments resulting from ambiguities in the formula that determined the DWR remittance rate that were resolved in September 2003. The Utility has filed an application for rehearing of this decision with the CPUC.

In 2002, the Utility’s interest expense increased approximately $14 million, or 1%, compared to 2001 due to the Utility’s Chapter 11 proceeding, which resulted in higher negotiated interest rates and an increased level of unpaid debts accruing interest.

As discussed above in the Cash Requirements of the Plan of Reorganization section, the Utility’s ongoing interest expense will be dependent upon the size of the refinancing and associated rates established at the effective date of the Plan of Reorganization.

PG&E Corporation’s revenues consist mainly of billings to its affiliates for services rendered, all of which are eliminated in consolidation. PG&E Corporation’s operating expenses consist mainly of employee compensation and payments to third parties for goods and services. Generally, PG&E Corporation’s operating expenses are allocated to affiliates. These allocations are made without mark-up. Operating expenses allocated to affiliates are eliminated in consolidation.

In connection with refinancings of PG&E Corporation’s debt in 2001, PG&E Corporation granted to affiliates of the lenders warrants to purchase up to 5% of NEGT’s outstanding common stock. These warrants were originally recorded at their fair value of approximately $151 million. The fair value of the warrants is marked to market at each reporting period. Changes in the fair value of the warrants are recorded as operating expense until exercised. This expense is not allocated to affiliates nor is it eliminated. Increases in the fair value of the warrants are recorded as operating expense and conversely declines in the fair value of NEGT warrants are recorded as a contra expense. The contra expense reflects the decline in the value of the unexercised warrants to their current recorded value of zero, of approximately $140 million in 2002 and approximately $11 million in 2001.

PG&E Corporation’s interest expense is not allocated to its affiliates. In 2003, PG&E Corporation’s interest expense decreased by approximately $42 million, or 18%, compared to 2002. The decrease is mainly due to a decrease in amortization of deferred charges and unamortized loan fees during 2003, compared to 2002. During the third quarter of 2003, PG&E Corporation wrote off approximately $89 million of unamortized loan fees, loan discounts and prepayment fees when it repaid loans due originally in 2006. During the third quarter of 2002, PG&E Corporation wrote off $153 million of unamortized loan fees and discounts when it repaid $600 million of principal and modified a $420 million loan under PG&E Corporation’s credit agreement. This later write-off was substantially responsible for the increase in interest expense in 2002 compared to 2001.

At December 31, 2003, PG&E Corporation had approximately $4.4 billion of consolidated cash and cash equivalents and restricted cash, of which approximately $764 million was restricted. PG&E Corporation and the Utility maintain separate bank accounts. At December 31, 2003, PG&E Corporation on a stand-alone basis had cash and cash equivalents of approximately $673 million and restricted cash of $361.5 million. At December 31, 2003 the Utility had cash and cash equivalents and restricted cash of approximately $3.4 billion. PG&E Corporation and the Utility primarily invest their cash in money market funds and in short-term obligations of the U.S. Government and its agencies.

At December 31, 2003, the Utility had approximately $3.4 billion of cash and cash equivalents. The principal source of the Utility’s cash is payments from its customers. Since wholesale electricity prices moderated and electricity surcharges were fully implemented in mid-2001, the cash generated by the Utility’s operations has exceeded its ongoing cash requirements.

During its Chapter 11 proceeding, the Utility has not had access to the capital markets and has met all its ongoing cash requirements, including its capital expenditures requirements, with cash generated by its operations. In addition, the Utility has paid interest on certain pre-petition liabilities and repaid the principal of maturing mortgage bonds with bankruptcy court approval. The Utility expects to pay allowed creditor claims from the proceeds of a public offering of long-term debt, cash on hand, and draws on revolving credit and accounts receivable facilities established in connection with the implementation of the Plan of Reorganization. The Utility also will establish an escrow account for disputed claims and deposit cash into these accounts to pay the claims as they are resolved.

Of the Utility’s cash and cash equivalents at December 31, 2003, approximately $403 million is restricted as to its use. The restrictions arise from deposits under certain third party agreements, amounts held in escrow as collateral required by the ISO and deposits securing workers’ compensation obligations.

After the effective date of its Plan of Reorganization, the Utility is expected to fund its operating expenses and its capital expenditures program from internally generated funds. The Utility will maintain commercial bank lines and other short-term borrowing facilities in order to provide sufficient liquidity to fund seasonal changes in working capital, balancing account under-collections, and credit support for collateralized procurement activities. The Utility is also expected to utilize a portion of its internally generated funds to make scheduled debt service payments and achieve the target capital structure provided for in the Settlement Agreement by late 2005. Once the Utility reaches this target capital structure, it will commence distributions to PG&E Corporation in the form of dividends and stock repurchases. Thereafter, a small portion of the Utility’s capital expenditures program is expected to be funded with the issuance of new debt securities.

The Utility’s cash flows from operating activities consist of monthly sales to its customers and operating expenses, other than expenses such as depreciation that do not require the use of cash. Cash flows from operating activities are also impacted by collections of accounts receivable and payments of liabilities previously recorded.

The Utility’s cash flows from operating activities for 2003, 2002 and 2001 were as follows:

Although net income decreased by approximately $896 million in 2003 compared to 2002, in 2003, net cash provided by operating activities increased by approximately $836 million compared to 2002 mainly due to the following factors:


	•	Payments on amounts classified as liabilities subject to compromise decreased by approximately $1.3 billion in 2003, compared to 2002 due to significant pre-petition and post-petition payments made in 2002 under bankruptcy court-approved settlements;

	•	Net cash provided by operating activities was partially offset by an increase in accounts receivable. This increase was mainly due to the settlement in 2003 of an amount payable to the DWR that was recorded as an offset to the Utility’s customer accounts receivable balance in 2002. Amounts payable to the DWR are offset against amounts receivable from the Utility’s customers for energy supplied by the DWR reflecting the Utility’s role as a billing and collection agent for the DWR’s sales to the Utility’s customers; and

	•	Net income in 2002 included a non-cash reduction of approximately $970 million to cost of electricity related to the reversal of ISO charges.

In 2002, the net cash provided by operating activities decreased by approximately $3.6 billion compared to 2001, mainly due to the following factors:


	•	The Utility’s filing of its Chapter 11 petition in April 2001 automatically stayed all payments on then-existing liabilities. After the filing, the Utility resumed paying its ongoing expenses in the ordinary course of business. As a result, the growth in accounts payable was approximately $1.1 billion lower in 2002 than in 2001;

	•	The Utility received an approximately $1.1 billion income tax refund in 2001 and no comparable refund was received in 2002;

	•	In 2002, the Utility repaid approximately $901 million in pre-petition liabilities owed to qualifying facilities under bankruptcy court-approved agreements; and

	•	In 2002, under a bankruptcy court order, the Utility paid approximately $1.0 billion in pre-petition and post-petition interest to holders of certain undisputed claims, trade creditors and certain other general unsecured creditors. These interest payments included approximately $433 million of accrued interest on financial debt previously classified as liabilities subject to compromise.

The Utility will maintain commercial bank lines of credit and other short-term borrowing facilities in order to provide sufficient liquidity to fund seasonal changes in working capital, balancing account under-collections, and credit support for collateralized procurement activities.

The Utility’s investing activities consist of construction of new and replacement facilities necessary to deliver safe and reliable electricity and natural gas services to its customers. Cash flows from operating activities have been sufficient to fund the Utility’s capital expenditure requirements during 2003, 2002 and 2001. Year to year variances depend upon the amount and type of construction activities, which can be influenced by storm and other damage.

The Utility’s cash flows from investing activities for 2003, 2002 and 2001 were as follows:

In 2003, net cash used by investing activities increased by approximately $254 million compared to 2002. This increase was mainly due to an increase in capital expenditures related to electricity transmission network upgrades and new electricity capacity and transmission development projects in 2003 and other investing activities during 2003. Cash flows from other investing activities related mainly to nuclear decommissioning funding and the change in nuclear fuel inventory during the period.

In 2002, net cash used by investing activities increased by approximately $171 million compared to 2001 mainly due to an increase in capital expenditures related to electricity transmission substation and line improvements intended to improve system reliability.

During its Chapter 11 proceeding, the Utility’s financing activities have been limited to repayment of secured debt obligations as authorized by the bankruptcy court. During this period, the Utility has not had access to the capital markets. As discussed below, the Utility expects to issue significant amounts of debt in connection with the implementation of the Plan of Reorganization and establish revolving credit and accounts receivable facilities to provide additional liquidity at and after the effective date of the Plan of Reorganization.

The Utility’s cash flows from financing activities for 2003, 2002 and 2001 were as follows:

In 2003, net cash used by financing activities decreased by approximately $52 million compared to 2002. With bankruptcy court approval, the Utility repaid approximately $281 million in principal on its mortgage bonds that matured in August 2003. PG&E Funding, LLC, a wholly owned subsidiary of the Utility, also repaid approximately $290 million in principal on its rate reduction bonds. The rate reduction bonds are not included in the Utility’s Chapter 11 proceeding. PG&E Funding, LLC pays the principal and interest on the rate reduction bonds from a specific rate element in Utility customers’ bills. The Utility remits the collection of these billings to PG&E Funding, LLC on a daily basis.

In 2002, net cash used by financing activities increased by approximately $193 million compared to 2001. With bankruptcy court approval, the Utility repaid approximately $333 million in principal on its mortgage bonds that

Financing activities used approximately $430 million of net cash in 2001 mainly for repayments of long-term debt and rate reduction bonds. The repayment of long-term debt included payments of approximately $18 million on medium-term notes and approximately $93 million for mortgage bonds before the Utility’s Chapter 11 filing.

At December 31, 2003 PG&E Corporation’s stand-alone cash and cash equivalents balance was approximately $673 million. PG&E Corporation’s sources of funds are dividends from the Utility, issuance of its common stock and external financing. The Utility did not pay any dividends to PG&E Corporation in 2003, 2002 or 2001. PG&E Corporation also has $361.5 million of restricted cash which is recorded in noncurrent other assets at December 31, 2003. This restricted cash pertains to the tax dispute with NEGT described above.

PG&E Corporation’s cash flows from operating activities consist mainly of billings to its affiliates for services rendered and payments for employee compensation and goods and services provided by others to PG&E Corporation. PG&E Corporation also incurs interest costs associated with its debt. PG&E Corporation’s interest costs are not passed on to its affiliates nor are the benefits or detriments of the consolidated tax return. The benefits of the consolidated tax return have created cash flow from operating activities for PG&E Corporation during 2003, 2002 and 2001. NEGT’s tax dispute with PG&E Corporation is discussed above.

PG&E Corporation’s consolidated cash flows from operating activities for 2003, 2002 and 2001 were as follows:

In 2003, PG&E Corporation’s consolidated cash flows provided by operating activities increased by approximately $1.7 billion compared to 2002, mainly due to an increase in the Utility’s net cash provided from operating activities as discussed above, partially offset by a decrease in net cash provided from NEGT’s operating activities as a result of realized losses generated through July 7, 2003.

In 2002, PG&E Corporation’s cash flows provided by operating activities decreased by approximately $4.1 billion compared to 2001, mainly due to the continued operation of the Utility under Chapter 11 and the prior year impact of an income tax refund.

PG&E Corporation’s stand-alone cash flows for investing activities consist mainly of the purchase of office equipment and computers and totaled approximately $0.4 million for 2003, $1.0 million for 2002 and $3.6 million for 2001.

PG&E Corporation’s cash flows from financing activities consist mainly of cash generated from debt refinancings and the issuance of common stock.

PG&E Corporation’s cash flows from financing activities for 2003, 2002 and 2001 were as follows:

In March 2001, PG&E Corporation borrowed approximately $1.0 billion under a credit facility and used the proceeds to pay commercial paper, borrowings under PG&E Corporation’s then-existing revolving credit facility and a dividend to its shareholders declared in the fourth quarter of 2000. The credit facility also provided affiliates of the lenders with options to purchase up to 2 or 3% of NEGT’s outstanding common stock (depending on how long the loans were outstanding) at an exercise price of $1.00. Options representing 3% of NEGT were exercised during the first quarter of 2003.

The March 2001 credit facility was amended in November 2001 to extend the term of the credit facility from March 2, 2003 to March 2, 2004 and allow PG&E Corporation to further extend the term for two additional one-year periods. PG&E Corporation issued the lenders additional options equal to 1% of NEGT’s common stock. The credit facility was further amended in March 2002 to make the two additional one-year extensions, subject to certain conditions, including an accelerated principal payment and the grant of additional options to purchase 1% of NEGT’s outstanding common stock.

This credit facility was refinanced in June 2002, through the issuance of $1.02 billion of debt under an amended credit agreement, which also granted the lenders warrants to purchase approximately 2,397,541 shares of PG&E Corporation’s common stock at an exercise price of $0.01 per share. Under the June 2002 amended agreement, the options granted to the lenders in March 2001 and 2002 to purchase 1% of NEGT’s outstanding common stock for each one-year extension, were reduced to approximately 0.87%.

In August 2002, PG&E Corporation made a voluntary prepayment of $600 million of principal plus interest of $7 million, reducing the outstanding balance under the amended credit agreement to $420 million.

In October 2002, the amended credit agreement was further amended to increase the size of the facility by $300 million to a total of $720 million. PG&E Corporation borrowed the $300 million in January 2003, receiving net proceeds of approximately $237 million after funding an interest reserve account of approximately $54 million and paying a funding fee of approximately $9 million. In connection with the amendment, PG&E Corporation issued to the lenders additional warrants to purchase 2,669,390 shares of PG&E Corporation’s common stock, at an exercise price of $0.01 per share.

Also, in June 2002, PG&E Corporation issued $280 million of 7.50% convertible subordinated notes due June 30, 2007. PG&E Corporation may convert the notes at any time into 18,558,655 shares of PG&E Corporation’s common stock. In October 2002, the notes were amended to eliminate the cross-default provisions related to NEGT, increase the interest rate to 9.50%, extend the maturity to June 30, 2010 and give the holders a one-time right to require PG&E Corporation to repurchase the notes on June 30, 2007 at a purchase price equal to the principal amount of the notes. The holders of the convertible notes are also entitled to receive dividend payments as if they hold the common shares subject to the conversion feature.

In July 2003, PG&E Corporation issued $600 million of 6 7/8% Senior Secured Notes due 2008. The notes are secured by a pledge of approximately 94% of the Utility’s outstanding common stock and are senior to all PG&E Corporation’s existing and future subordinated debt, including its convertible subordinated notes. Interest on the notes is payable semi-annually in arrears on January 15 and July 15, commencing January 15, 2004. PG&E Corporation can

redeem the notes at any time at its option at a premium. In addition, in certain circumstances involving a change of control, spin-off, or reorganization event, PG&E Corporation is required to offer to purchase the notes. The approximately $581 million in net proceeds of the offering, together with cash on hand, were used to repay $720 million outstanding under PG&E Corporation’s credit agreement, accrued in-kind interest of approximately $15 million and a prepayment premium of approximately $52 million.

In 2003, PG&E Corporation’s cash flows from financing activities include approximately $166 million from the issuance of common stock for 401(k) plan stock purchases and stock option and warrant exercises. PG&E Corporation’s cash flows from financing activities include approximately $217 million in 2002 and approximately $15 million in 2001 for similar common stock issuances. In addition, approximately $109 million of dividends were paid in 2001 with no comparable activity in 2002 or 2003.

After the effective date of the Plan of Reorganization, the Utility expects to fund its operating expenses and capital expenditures substantially from internally generated funds, although it may issue debt for these purposes in the future. In addition, on or about the effective date of the Plan of Reorganization, the Utility expects to establish one or more credit facilities in the amount of approximately $1.5 billion. These facilities are intended to be used for the purposes of funding its operating expenses and seasonal fluctuations in working capital, providing letters of credit and paying a small portion of the allowed claims under the Plan of Reorganization. The Utility currently anticipates approximately $800 million of these credit facilities will be available for revolving borrowings and the remaining approximately $650 million will be allocated to letters of credit. While the Utility expects to enter into these new credit facilities on or about the effective date of the Plan of Reorganization, there can be no assurance that it will be successful and, if so, on what terms.

The Utility expects that the cash it will retain after the effective date of the Plan of Reorganization, together with cash from operating activities and available under the credit facilities it expects to establish, as described above, will provide for seasonal fluctuations in cash requirements and will be sufficient to fund its operations and its capital expenditures for the foreseeable future.

Historically, in determining whether to, and at what level to, declare a dividend, PG&E Corporation has considered a number of financial factors, including sustainability, financial flexibility, and competitiveness with investment opportunities of similar risk, as well as other factors, including the regulatory and legislative environment, operating performance, and capital and financial resources in general.

Other than payment in 2001 of the dividend declared in the fourth quarter of 2000, PG&E Corporation has not declared or paid a dividend in 2003, 2002 or 2001. Further, the 6 7/8% Senior Secured Notes issued by PG&E Corporation prohibit PG&E Corporation from declaring or paying dividends or repurchasing its common stock. Notwithstanding this restrictive covenant, PG&E Corporation may declare a dividend or repurchase a portion of its common stock if:


	•	Certain financial criteria are met;

	•	The 6 7/8% Senior Secured Notes are rated Baa3 or better by Moody’s and BBB- or better by S&P; or

	•	Following the implementation of a plan of reorganization by the Utility, the dividends or stock repurchases are funded from proceeds of cash distributions to PG&E Corporation from the Utility.

The Utility has not declared or paid any common or preferred dividends in 2003, 2002 or 2001. While in Chapter 11, the Utility is prohibited from paying any common or preferred dividends without bankruptcy court approval. Among other restrictions, the Utility must maintain a capital structure authorized by the CPUC. The Utility expects to achieve the target capital structure provided for in the Settlement Agreement by the second half of 2005.

The following table provides information about the Utility’s and PG&E Corporation’s contractual obligations and commitments at December 31, 2003. This table includes obligations based on their existing terms. The Utility expects to repay some of these obligations on, or as soon as practicable after, the effective date of the Plan of Reorganization. This table does not include payments on the long-term debt the Utility expects to issue, and credit facilities it expects to establish, in connection with the Plan of Reorganization.


⁽¹⁾	This table does not include DWR allocated contracts because the DWR is currently legally and financially responsible for these contracts.

⁽²⁾	Includes commitments for operating lease agreements mostly for office space in the aggregate amount of approximately $91 million, capital infusion agreements for limited partnership interests in the aggregate amount of approximately $16 million, contracts to retrofit generation equipment at the Utility’s facilities in the aggregate amount of approximately $62 million, load-control and self-generation CPUC initiatives in the aggregate amount of approximately $35 million, contracts for local and long-distance telecommunications and other software in the aggregate amount of approximately $16 million and capital expenditures for which the Utility has contractual obligations or firm commitments.

⁽³⁾	Contribution estimates conform to forecasted amounts in the pending 2003 GRC. Actual contributions are dependent upon the outcome of the 2003 GRC. Contribution estimates after 2006 are subject to future GRC test years.

⁽⁴⁾	Preferred dividend and redemption requirement estimates beyond 5 years do not include non-redeemable preferred stock dividend payments as these continue in perpetuity.

The Utility’s contractual commitments include power purchase agreements (including agreements with qualifying facilities, irrigation districts and water agencies and renewable energy providers), natural gas supply and transportation agreements, nuclear fuel agreements, operating leases and other commitments.

Qualifying Facilities. The Utility’s power purchase agreements with qualifying facilities require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility’s actual electricity output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility’s total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement. Capacity payments total approximately $500 million annually. The energy payments under the power purchase agreements with the qualifying facilities are typically based upon a CPUC-approved short-run avoided cost that is currently indexed to natural gas prices. Avoided costs are the incremental costs that an electric utility would incur to generate or purchase electricity but for the purchase from the qualifying facilities. As a result of the California energy crisis and the Utility’s Chapter 11 filing, in July 2001, 197 qualifying facilities amended their contracts to fix their energy payments at $0.054 per kWh through July 2006. The remaining qualifying facility contracts calculate payment based on short-run avoided cost. Beginning in August 2006, the energy payments under all qualifying facility contracts will revert back to the short-run avoided cost rates.

At December 31, 2003, the Utility had qualifying facility power purchase agreements with 300 qualifying facilities for approximately 4,400 megawatts, or MW, that are in operation. Agreements for approximately 4,000 MW expire between 2004 and 2028. Qualifying facility power purchase agreements for approximately 400 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. On January 22, 2004, the CPUC adopted a decision that requires California investor-owned electric utilities to allow owners of qualifying facilities with power purchase agreements expiring before the end of 2005 to extend these contracts for five years. Qualifying facility power purchase agreements accounted for approximately 20% of the Utility’s 2003 electricity sources, approximately 25% of its 2002 electricity sources and approximately 21% of its 2001 electricity sources. No single qualifying facility power purchase agreement accounted for more than 5% of the Utility’s electricity sources during any of these periods.

In a proceeding pending at the CPUC, the Utility has requested refunds in excess of $500 million for overpayments from June 2000 through March 2001 made to qualifying facilities. Under the Settlement Agreement, the net after-tax amount of any qualifying facility refunds that the Utility actually realizes in cash, claim offsets or other credits would reduce the $2.21 billion after-tax regulatory asset. While PG&E Corporation and the Utility are unable to estimate the outcome of this proceeding, they believe the proceeding will not have a material adverse effect on their financial condition or results of operations.

Irrigation Districts and Water Agencies. The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements regardless of whether any hydroelectric power is supplied and variable payments for operating and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. The Utility’s irrigation district and water agency contracts accounted for approximately 5% of its 2003 electricity sources, approximately 4% of its 2002 electricity sources and approximately 3% of its 2001 electricity sources.

Electricity Purchases to Satisfy the Residual Net Open Position. On January 1, 2003, the Utility resumed buying electricity to meet its residual net open position. During 2003, more than 14,000 GWh of energy was bought and sold in the wholesale market to manage the 2003 residual net open position. Most of the Utility’s contracts entered into in 2003 had terms of less than one year. During 2004, the Utility plans to enter into contracts of longer duration to satisfy its near-term residual net open position.

Renewable Energy Requirement. California law requires that, beginning in 2003, each California investor-owned electric utility must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility estimates the annual procurement target will initially require it to purchase approximately 750 GWh of electricity from renewable resources each year. The Utility

The Utility purchases natural gas directly from producers and marketers in both Canada and the United States to serve its core customers. The contract lengths and natural gas sources of the Utility’s portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. At December 31, 2003, the Utility had a $10 million collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable for the purpose of securing the purchase of natural gas. The core natural gas inventory also may be pledged, but only if the amount of the Utility’s natural gas customer accounts receivable is less than the amount that it owes to natural gas suppliers. To date, the amount of the Utility’s accounts receivable pledge has been sufficient. The pledged amount of customer accounts receivable was approximately $561 million at December 31, 2003 and $513 million at December 31, 2002. The amount owed to natural gas suppliers was approximately $96 million at December 31, 2003 and $29 million at December 31, 2002. It is anticipated that the pledge of the natural gas customer accounts receivable and natural gas inventory will be replaced with letters of credit no later than the effective date of the Plan of Reorganization.

The Utility also has long-term natural gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges. The total demand charges that the Utility will pay each year may change periodically as a result of changes in regulated tariff rates. The total demand and volumetric transportation charges the Utility incurred under these agreements were approximately $131 million in 2003, $101 million in 2002 and $239 million in 2001.

The Utility has purchase agreements for nuclear fuel. These agreements have terms ranging from two to five years and are intended to ensure long-term fuel supply. These agreements are with a number of large, well-established international producers of nuclear fuel in order to diversify the Utility’s commitments and provide security of supply. Pricing terms are also diversified, ranging from fixed prices to base prices that are adjusted using published information. Deliveries provided under nine of the eleven contracts in place at the end of 2003 will end by 2005. In most cases, the Utility’s nuclear fuel agreements are requirements-based. Payments for nuclear fuel amounted to approximately $57 million in 2003, $70 million in 2002 and $50 million in 2001.

In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnection of the Utility’s and WAPA’s electricity transmission systems, the use of the Utility’s electricity transmission and distribution systems by WAPA, and the integration of the Utility’s and WAPA’s customer demands and electricity resources. These contracts give the Utility access to WAPA’s excess hydroelectric power and obligate the Utility to provide WAPA with electricity when its resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004, but termination is subject to FERC approval, which the Utility expects to receive.

The contractual commitments table above does not include the Utility’s WAPA commitment because the costs to fulfill the Utility’s obligations to WAPA cannot be accurately estimated at this time. Both the purchase price and the amount of electricity WAPA will need from the Utility in 2004 are uncertain. However, the Utility expects that the cost of meeting its contractual obligations to WAPA will be greater than the amount that the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, the Utility’s estimated net costs, based upon its portfolio, including DWR power and bond charges, and after subtracting revenues received from WAPA, for electricity delivered under the contracts were approximately $233 million in 2003, $127 million in 2002 and $350 million in 2001.

operational control of their electricity transmission systems to the ISO. In addition, as a party to the TCA, the Utility is responsible for a share of the costs of reliability must-run, or RMR, agreements between the ISO and owners of the power plants subject to RMR agreements, or RMR Plants. The Utility also is an owner of some of these RMR Plants for which the Utility receives revenue from the ISO. Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO’s demand.

At December 31, 2003, the ISO had RMR agreements for which the Utility could be obligated to pay the ISO an estimated $446 million in net costs during the period January 1, 2004 to December 31, 2005. These costs are recoverable under applicable ratemaking mechanisms.

It is possible that the Utility may receive a refund of RMR costs that the Utility previously paid to the ISO. In June 2000, a FERC administrative law judge issued an initial decision approving rates that, if affirmed by the FERC, would require the subsidiaries of Mirant Corporation, or Mirant, that are parties to three RMR agreements with the ISO to refund to the ISO, and the ISO to refund to the Utility, excess payments of approximately $340 million, including interest, for availability of Mirant’s RMR Plants under these agreements. However, on July 14, 2003, Mirant filed a petition for reorganization under Chapter 11 and on December 15, 2003, the Utility filed claims in Mirant’s Chapter 11 proceeding including a claim for an RMR refund. The Utility is unable to predict at this time when the FERC will issue a final decision on this issue, what the FERC’s decision will be, and the amount of any refunds, which may be impacted by Mirant’s Chapter 11 filing. It is uncertain how the resolution of this matter would be reflected in rates.

The Utility has other commitments relating to operating leases, capital infusion agreements, equipment replacements, software licenses, the self-generation incentive program exchange agreements and telecommunication contracts. At December 31, 2003, the future minimum payments related to other commitments were as follows:

The Utility’s current commitments under financing arrangements include obligations to repay mortgage bonds, senior notes, medium-term notes, pollution control bond-related agreements, deferrable interest subordinated debentures, lines of credit, reimbursement agreements associated with letters of credit, floating rate notes and commercial paper, substantially all of which are pre-petition obligations. On the effective date of the Plan of Reorganization, the Utility expects to reinstate certain pollution control bond-related obligations in the amount of approximately $814 million. The balance of the pre-petition obligations will be paid in full in cash, plus applicable interest, on or as soon as practicable after the effective date of the Plan of Reorganization. After the effective date, the Utility’s obligations will also include, in addition to the reinstated pollution control bond-related obligations, the long-term debt issued in connection with the Plan of Reorganization and the revolving credit and accounts receivable facilities implemented on or about the effective date.

In addition, PG&E Funding, LLC must make scheduled payments on its rate reduction bonds. The balance owed on these bonds at December 31, 2003 was approximately $1.16 billion. Annual principal payments on the rate reduction bonds total approximately $290 million. The rate reduction bonds are expected to be fully retired by the end of 2007.

The Utility’s investment in plant and equipment totaled approximately $1.7 billion in 2003, $1.5 billion in 2002 and $1.3 billion in 2001.

The following table reflects the Utility’s estimated capital expenditures for the next five years. Capital expenditures for which contracts or firm commitments exist have, in addition to being included in the table below, been included in the table above, which details the Utility’s contractual obligations and commitments at December 31, 2003.


	•	New customer connections and expansion of the existing electricity and natural gas distribution systems anticipated to average approximately $400 million annually over the next five years;

	•	Replacements and upgrades to portions of the Utility’s electricity distribution system anticipated to average approximately $300 million annually over the next five years;

	•	Replacement of natural gas distribution pipelines expected to total approximately $375 million over the next five years;

	•	Substation upgrades and expansion of line capacity of the electricity transmission system expected to average approximately $260 million annually over the next five years;

	•	Replacements and upgrades to the Utility’s natural gas transportation facilities expected to total approximately $600 million over the next five years;

	•	Replacement of turbines and steam generators and other equipment, including additional security measures, at the Utility’s Diablo Canyon power plant, replacements and upgrades to the Utility’s hydroelectric generation facilities and costs associated with relicensing the Utility’s hydroelectric generation facilities expected to average approximately $180 million annually over the next five years; and

	•	Investment in common plant, including computers, vehicles, facilities and communications equipment, expected to average approximately $150 million annually over the next five years.

The Utility anticipates that its capital expenditures in the next five years will be somewhat higher than capital expenditures in recent years. These additional expenditures are necessary to replace aging and obsolete equipment and accommodate anticipated electricity and natural gas load growth. The Utility retains the ability to delay or defer substantial amounts of these planned expenditures in light of changing economic conditions and changing technology. It is also possible that these projects may be replaced by other projects. Consistent with past practice, the Utility expects that any capital expenditures will be included in its rate base and recoverable in rates.

The discussion above does not include any capital expenditures for new generation facilities. The residual net open position is expected to increase over time. To meet this need, the Utility will need to enter into contracts with third-party generators for additional supplies of electricity, develop or otherwise acquire additional generation facilities or satisfy its residual net open position through a combination of the two. The discussion above also does not include any capital expenditures necessary to implement advanced metering improvements.

In January 2001, the CPUC authorized increases in electricity rates of $0.01 per kWh, in March 2001 of another $0.03 per kWh and in May 2001 of an additional $0.005 per kWh. The use of these surcharge revenues was restricted to “ongoing procurement costs” and “future power purchases.” In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the surcharges to be used to restore the Utility’s financial health by permitting the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. From January 2001 to December 31, 2003, the Utility recognized total surcharge revenues of approximately $8.1 billion, pre-tax. The rate design settlement includes a refund of approximately $125 million of surcharge revenues. Accordingly, at

December 31, 2003, the Utility has recorded a regulatory liability for the potential refund of approximately $125 million of surcharge revenues collected during 2003. In addition, if the CPUC requires the Utility to refund any amounts in excess of approximately $125 million, the Utility’s earnings could be materially adversely affected.

The CPUC is assessing the viability of implementing an advanced metering infrastructure for residential and small commercial customers. This infrastructure would enable the California investor-owned electric utilities to measure usage of electricity on a time-of-use basis and to charge demand responsive rates. The goal of demand responsive rates is to encourage customers to reduce energy consumption during peak demand periods and reduce peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility is implementing demand responsive tariffs for large industrial customers who already have advanced metering systems in place, and a statewide pilot program is in progress to test whether and how much residential and small commercial customers will respond to demand responsive rates. If the CPUC determines that it would be cost-effective to install advanced metering on a large-scale and orders the Utility to proceed with large scale development of advanced metering for residential and small commercial customers, the Utility expects that it would incur substantial costs to convert its meters, build the meter reading network, and build the data storage and processing facilities to bill its customers. The Utility would expect to recover through rates the capital investments and any ongoing operating costs associated with implementing the advanced metering improvements. The total deployment of an advanced metering infrastructure to all of the Utility’s electricity and natural gas customers using equipment and technology currently available may cost more than $1.0 billion (in 2003 dollars), based on a five-year installation schedule starting in 2005.

In June 2003, the Utility, along with a number of other parties, entered into the El Paso settlement, which resolves all potential and alleged causes of action against El Paso for its part in alleged manipulation of natural gas and electricity commodity and transportation markets during the period from September 1996 to March 2003. Under the El Paso settlement, El Paso will pay $1.5 billion in cash and non-cash consideration, of which approximately $550 million is now in an escrow account and approximately $875 million will be paid over 15 to 20 years. The Utility’s share of the $1.5 billion settlement is approximately $300 million. El Paso also agreed to a $125 million reduction in El Paso’s long-term electricity supply contracts with the DWR, to provide pipeline capacity to California and to ensure specific reserve capacity for the Utility, if needed. In October 2003, the CPUC approved an allocation of these refunds, under which the Utility’s natural gas customers would receive approximately $80 million and its electricity customers would receive approximately $216 million. The settlement was approved by the FERC in November 2003 and by the San Diego Superior Court in December 2003. At least one appeal of the San Diego Superior Court’s approval has been filed; however, the Utility believes that it is probable that the El Paso settlement will not be overturned on appeal. The Utility’s proposed electricity rate reduction in 2004, filed with the CPUC on January 26, 2004, included a reduction of $79 million to the $2.21 billion after-tax regulatory asset related to this El Paso settlement. In December 2003, the Utility also proposed a gas rate reduction related to this El Paso settlement of $29 million to be implemented in 2004.

On December 23, 2003, the Utility entered into a settlement agreement with five subsidiaries of Enron Corporation, or Enron, settling certain claims between the Utility and Enron, or the Enron settlement. The Enron settlement will become effective if approved by the bankruptcy courts overseeing both the Utility’s and Enron’s Chapter 11 proceedings. A hearing for approval of the Enron settlement is currently scheduled in the Utility’s Chapter 11 proceeding on March 5, 2004. A hearing was held in the Enron bankruptcy court on February 5, 2004 and the matter was submitted. If the Enron settlement is approved, the Utility will receive an after-tax credit of approximately $90 million that will reduce the $2.21 billion after-tax regulatory asset as called for in the Settlement Agreement. In its January 26, 2004 filing with the CPUC proposing an electricity rate reduction, the Utility has reduced the revenue requirement related to the $2.21 billion after-tax regulatory asset to reflect this after-tax credit.

The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered.

The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:


	•	After assumption, the Utility’s issuer rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating by S&P will be no less than A;

	•	The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

	•	The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

The Utility is regulated primarily by the CPUC and the FERC. The FERC is an independent agency within the U.S. Department of Energy, or DOE, that, among other things, regulates the transmission of electricity and the sale for resale of electricity in interstate commerce. The CPUC has jurisdiction to, among other things, set the rates, terms and conditions of service for the Utility’s electricity distribution, natural gas distribution and natural gas transportation and storage services in California.

Frozen electricity rates, which began on January 1, 1998, were designed to allow the Utility to recover its authorized utility costs and to the extent frozen rates generated revenues in excess of these costs, to recover the Utility’s transition costs. Although the surcharges implemented in 2001 effectively increased the actual rate under the frozen rate structure, increases in the Utility’s authorized revenue requirements did not increase the Utility’s revenues. In addition, DWR revenue requirements reduced the Utility’s revenues under the frozen rate structure. As a result of revised electricity rates discussed below and a January 2004 CPUC decision determining that the rate freeze ended on January 18, 2001, the Utility expects that once approved by the CPUC, its rates will reflect cost of service whereby the Utility’s rates are calculated based on the aggregate of various authorized rate components. Changes in any individual revenue requirement will change customers’ electricity rates.

On January 26, 2004, the Utility filed revised electricity rates with the CPUC to implement the rate changes based on the Utility’s 2004 forecast revenue requirements. These rates reflect allocation of the Utility’s revenue requirements in accordance with the rate design settlement entered into with a number of consumer groups and government agencies, including TURN and the CPUC’s Office of Ratepayer Advocates, or ORA. The rate design settlement agreement has been submitted to the CPUC for approval. The revised rates and forecast revenue requirements are based on, and ultimately will be adjusted to reflect, pending or final CPUC decisions including:


	•	The Utility’s 2003 GRC;

	•	The allocation of the DWR’s 2004 revenue requirements;

	•	Pending energy supplier refunds, claim offsets or other credits pursuant to the Settlement Agreement; and

	•	The calculation of any over-collection of the surcharge revenues for 2003.

Based on the revised revenues filed by the Utility on January 26, 2004, current electricity revenues are expected to be reduced by approximately $860 million as compared to revenues generated at current rates. On February 11,

2004, a proposed decision was issued which, if ultimately approved by the CPUC, instead is expected to reduce the Utility’s current electricity revenues by $799 million. The most significant portion of the difference between the $799 million included in the proposed decision and the $860 million filed by the Utility relates to a proposed decrease in the DWR’s revenue requirement included in the Utility’s January 26, 2004 rate filing. In the January 26, 2004 rate filing, the Utility had estimated that the DWR’s revenue requirement would be reduced by approximately $79 million related to the DWR’s share of the El Paso settlement. However, the DWR protested the Utility’s rate filing, indicating that the amount of its share of the El Paso settlement was unknown and that the DWR had not changed its revenue requirement as a result of the El Paso settlement.

The February 11, 2004 proposed decision orders the Utility to amend its January 26, 2004 filing containing the revised electricity rates before March 1, 2004. The CPUC is expected to consider the rate design settlement at its meeting on February 26, 2004. If approved, the new rates are intended to be effective March 1, 2004 or shortly thereafter, and the revenue reduction will be retroactive to January 1, 2004. The Utility believes it is probable that the CPUC will approve this electricity rate reduction and resulting revenue reduction in 2004.

The CPUC determines the amount of authorized base revenues the Utility can collect from customers to recover its basic business and operational costs for electricity and natural gas distribution operations and for electricity generation operations in a GRC. The Utility’s last GRC was its 1999 GRC, approved by the CPUC in 2000. The 2003 GRC has been filed, testimony has been given before the CPUC and the Utility is awaiting a final decision. Any revenue requirement change resulting from a final decision will be retroactive to January 1, 2003.

In July 2003, the Utility and various intervenors (ORA, TURN, Aglet Consumer Alliance, and the City and County of San Francisco) filed a joint motion with the CPUC seeking approval of a settlement agreement resolving specific issues related to the cost of operating the Utility’s electricity generation facilities, or the generation settlement. In September 2003, the Utility and various intervenors (ORA, TURN, Aglet Consumer Alliance, the Modesto Irrigation District, the Natural Resources Defense Council and the Agricultural Energy Consumers Association) filed a joint motion with the CPUC seeking approval of the GRC settlement. The GRC settlement, together with the generation settlement, resolves all disputed economic issues among the settling parties related to the Utility’s electricity distribution, natural gas distribution and generation revenue requirements, with the exception of the Utility’s request that the CPUC include the costs of a pension contribution in the Utility’s revenue requirement. The CPUC will resolve the pension contribution issue, as well as other issues raised by non-settling intervenors, in its final decision. The CPUC agreed in the Settlement Agreement to act promptly on the 2003 GRC.

The GRC settlement would result in a total 2003 revenue requirement of approximately $2.5 billion for electricity distribution operations, representing an increase of approximately $236 million in the Utility’s electricity distribution revenue requirement over the current authorized amount. The GRC settlement provides that the electricity distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be approximately $7.7 billion, based on recorded 2002 plant, and including net weighted average capital additions for 2003 of approximately $292 million.

The GRC settlement also would result in a total 2003 revenue requirement of approximately $927 million for the Utility’s natural gas distribution operations, representing an increase of approximately $52 million in the Utility’s natural gas distribution revenue requirement over the current authorized amount. The GRC settlement also provides that the amount of natural gas distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be approximately $2.1 billion, based on recorded 2002 plant and including weighted average capital additions for 2003 of approximately $89 million.

Together with the generation settlement, the GRC settlement would result in a 2003 generation revenue requirement of $912 million, representing an increase of approximately $38 million in the Utility’s generation revenue requirement over the current authorized amount. This generation revenue requirement excludes fuel expense, the cost of electricity purchases, the DWR revenue requirements and nuclear decommissioning revenue requirements. Under the Settlement Agreement, the Utility’s adopted 2003 generation rate base of approximately $1.6 billion would be deemed just and reasonable by the CPUC and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation of the Utility’s electricity generation rate base would allow recognition of an after-tax regulatory asset of approximately $800 million (or approximately $1.3 billion pre-tax) as estimated at December 31, 2003. The Utility expects to record this regulatory asset when it meets the probability requirements for regulatory recovery in rates as provided for in SFAS No. 71, “Accounting for the Effects of

Certain Types of Regulation,” or SFAS No. 71. The individual components of the regulatory asset will be amortized over their respective lives. The weighted average life of these individual components is approximately 16 years.

The GRC settlement also provides for new balancing accounts to be established retroactive to January 1, 2004 that permit the Utility to recover its authorized electricity distribution and generation revenue requirement regardless of the level of sales. If sales levels do not generate the full revenue requirement in a period, rates in subsequent periods will be increased to collect the shortfall. Similarly, future rates will decrease if sales levels generate more than the full revenue requirement.

If the Utility prevails on the pension contribution issue, an additional revenue requirement of approximately $75 million would be allocated among electricity distribution, natural gas distribution and electricity generation operations.

Because the CPUC has yet to issue a final decision on the Utility’s 2003 GRC, the Utility has not included the natural gas distribution revenue requirement increase in its 2003 results of operations. If the CPUC approves a 2003 revenue requirement increase in 2004, the Utility would record both the 2003 and 2004 natural gas distribution revenue requirement increase in its 2004 results of operations.

In 2003 the Utility collected electricity revenue and surcharges subject to refund under the frozen rate structure. The amount of electricity revenue subject to refund pursuant to the rate design settlement in 2003 was $125 million, which incorporates the impact of the electric portion of the GRC settlement. The Utility has recorded a regulatory liability for such amount. If the revenue requirement that is ultimately approved in the Utility’s 2003 GRC is lower than the amounts described above, the regulatory liability would increase.

The CPUC also is considering a proposed reliability performance incentive mechanism for the Utility that would be in effect from 2004 through 2009. Under the proposed incentive mechanism, the Utility would receive up to $27 million in additional annual revenues to be recorded in a one-way balancing account to be spent exclusively on reliability performance activities with a goal of decreasing the duration and frequency of electricity outages. The Utility would be entitled to earn a maximum reward of up to $42 million each year depending on the extent to which the Utility exceeded the reliability performance improvement targets. Conversely, the Utility would be required to pay a penalty of up to $42 million a year depending on the extent to which it failed to meet the target.

On February 3, 2004, the CPUC reopened the GRC record for the purpose of taking further evidence regarding executive compensation and bonuses. The Utility has filed a report addressing these issues with the CPUC. PG&E Corporation and the Utility are uncertain how this matter will be resolved and when a final GRC decision will be issued.

If the GRC settlement is not approved by the CPUC, the Utility’s ability to earn its authorized rate of return for the years until the next GRC would be adversely affected. The parties to the GRC settlement have agreed that the Utility’s next GRC will determine rates for test year 2007. The Utility is unable to predict the outcome of the 2003 GRC or the impact it will have on its financial condition or results of operations.

The GRC settlement provides for yearly adjustments to the Utility’s base revenues, or attrition increases, for the years 2004, 2005 and 2006. The attrition increase will be based upon the change in the consumer price index, or CPI, subject to certain minimums and maximums.

The following tables show the multiplier, and the minimum and maximum percentage change for each revenue requirement along with estimates of the minimum and maximum total electricity distribution, natural gas distribution and generation revenue requirements for the years that would be covered by the 2003 GRC.


(1)	Generation calculations exclude an approximately $32 million incremental attrition adjustment in 2004 to reflect the need for a second refueling outage at the Diablo Canyon power plant during that year.

Because these attrition adjustments are based on the Utility’s current authorized capital structure and rate of return, they could be affected by future cost of capital proceedings. In addition, if the Utility prevails on the pension contribution issue as discussed above, the attrition adjustments would be slightly higher to reflect the addition of approximately $75 million to the Utility’s 2003 revenue requirements.

Each year the Utility must file an application with the CPUC to determine the Utility’s authorized capital structure and the authorized rate of return the Utility may earn on its electricity and natural gas distribution and electricity generation assets. For its electricity and natural gas distribution operations and electricity generation operations, the Utility’s currently authorized return on equity is 11.22% and its currently authorized cost of debt is 7.57%. The Utility’s currently authorized capital structure is 48.00% common equity, 46.20% long-term debt and 5.80% preferred equity.

The Utility must file a cost of capital application within 30 days after completing the financings to implement the Plan of Reorganization. For 2004, this cost of capital proceeding will also determine the authorized rate of return for natural gas transportation and storage. The application must reflect changes in capital structure, long-term debt and preferred stock costs, and costs associated with interest rate hedges. The Settlement Agreement provides that from January 1, 2004 until Moody’s has issued an issuer rating for the Utility of not less than A3 or S&P has issued a long-term issuer credit rating for the Utility of not less than A-, the Utility’s authorized return on equity will be no less than 11.22% per year and its authorized equity ratio will be no less than 52%. However, for 2004 and 2005, the Utility’s authorized equity ratio will equal the greater of the proportion of equity approved in the Utility’s 2004 and 2005 cost of capital proceedings and 48.6%.

The DWR filed a proposed $4.5 billion 2004 power charge revenue requirement and a proposed 2004 bond charge revenue requirement of approximately $873 million with the CPUC in September 2003. In January 2004, the CPUC issued a decision that adopted an interim allocation of the DWR’s proposed 2004 revenue requirements among the three California investor-owned electric utilities. The Utility customers’ share of the DWR power charge revenue requirement is approximately $1.8 billion after consideration of the DWR 2001-2002 adjustment discussed below. The January 2004 decision allocated the bond charge revenue requirement among the three California investor-owned electric utilities on an equal cents per kWh basis, which resulted in approximately $369 million being allocated to the Utility’s customers.

The CPUC will consider adopting a multi-year allocation of the DWR’s power charge revenue requirements in a second phase of the 2004 DWR power charge proceeding. If adopted, a multi-year allocation would replace the interim allocation for 2004. The Utility cannot predict the final outcome of this matter.

The DWR revenue requirements have been subject to various adjustments, including the reallocation of contracts among the California investor-owned electric utilities, adjustments to reflect actual deliveries and adjustments resulting from changes in allocation methodologies. In January 2004, the CPUC issued a decision finding that the Utility had over-remitted approximately $101 million in power charges to the DWR related to the DWR’s 2001-2002

As a result of the transition from frozen rates and the electricity procurement recovery mechanism described below, the collection of DWR revenue requirements, or any adjustments thereto, including the reduction in the 2004 revenue requirement related to 2001 through 2002, will not affect the Utility’s results of operations.

In May 2002, the CPUC ordered the California investor-owned electric utilities to increase the baseline allowances for certain residential customers, which reduced the Utility’s electricity revenues. An increase to a customer’s baseline allowance is an increase to the amount of monthly usage that is covered under the lowest possible electricity rate and exempt from certain surcharges. The CPUC deferred consideration of corresponding rate changes until a later phase of the proceeding and ordered the California investor-owned electricity utilities to track the under-collections associated with their respective baseline quantity changes in an interest-bearing balancing account. The Utility is charging the electricity revenue-related shortfall against earnings because it cannot predict the outcome of the later phase of the proceeding, nor can it conclude that recovery of the electric-related balancing account is probable. The total electricity revenue shortfall was approximately $70 million for the period from May through December 2002 and approximately $114 million for 2003.

Proposals have been made that include demographic revisions to baseline allowances, special allowances and changes to baseline territories or seasons that could range to up to an additional $55 million per year, plus $6 million in administration costs spread out over three to five years. However, a proposed decision issued by the CPUC in October 2003 would result in annual electric shortfalls of only $16 million, plus $2 million in initial administrative costs. The Utility will continue to charge any electricity revenue shortfalls to earnings until the CPUC implements the necessary recovery charges. The proposed decision adopting the rate design settlement if approved by the CPUC would provide for timely rate adjustments for prospective revenue shortfalls resulting from increased baseline allowances. The rate design settlement does not, however, provide for the recovery of shortfalls prior to the implementation of the rate design settlement.

Beginning January 1, 2003, the Utility resumed responsibility for procuring electricity for its residual net open position. The Utility’s residual net open position is expected to grow over time for a number of reasons, including:


	•	Periodic expirations of existing electricity purchase contracts;

	•	Periodic expirations or other terminations of the DWR allocated contracts. For the period 2004-2009, the DWR must-take contracts and contracts with mandatory capacity payments are expected to supply about 25% of the electricity demands of the Utility’s customers. For the period 2010-2012, the DWR must-take contracts and contracts with mandatory capacity payments are expected to supply less than 10% of the electricity demands of the Utility’s customers;

	•	Increases in the Utility’s customers’ electricity demands due to customer and economic growth or other factors; and

	•	Retirement or closure of the Utility’s electricity generation facilities.

In addition, unexpected outages at the Utility’s Diablo Canyon power plant, or any of the Utility’s other significant generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility’s residual net open position.

In January 2004, the CPUC adopted an interim decision that would require the California investor-owned electric utilities to achieve by January 1, 2008 an electricity reserve margin of 15-17% in excess of peak capacity electricity requirements and have a diverse portfolio of electricity sources. These requirements may increase the Utility’s residual net open position. Specific procedures contained in the decision relating to development and execution of the Utility’s procurement plans may also cause the cost of electricity to the Utility to increase.

Effective January 1, 2003, under California law the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the recorded procurement revenues and actual costs incurred under the Utility’s authorized procurement plans, excluding the costs

associated with the DWR allocated contracts and certain other items. The CPUC must review the revenues and costs associated with an investor-owned utility’s electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate, when the aggregate over-collections or under-collections exceed 5% of the utility’s prior year electricity procurement revenues, excluding amounts collected for the DWR. These mandatory adjustments will continue until January 1, 2006. The CPUC’s review of the Utility’s procurement activities will examine the Utility’s least-cost dispatch of its resource portfolio including the DWR allocated contracts, fuel expenses for the Utility’s electricity generation facilities, contract administration (including administration of the DWR allocated contracts) and the Utility’s electricity procurement contracts. As a result of this review, some of the Utility’s procurement costs could be disallowed. The Utility cannot predict whether a disallowance will occur or the size of any potential disallowance.

In February 2004, the Utility requested that the CPUC approve the Utility’s 2004 ERRA revenue requirement of approximately $2.2 billion associated with the Utility’s 2004 short-term procurement plan. Costs associated with electricity procurement contracts entered into prior to January 1, 2003, such as the qualifying facility contracts, are eligible for recovery under the ERRA provided the costs are under a CPUC authorized benchmark. The benchmark anticipated to be adopted by the CPUC for 2004 is $0.0518 per kWh, based upon a report prepared by the California Energy Commission. The CPUC will establish a benchmark for each year of the ERRA. Determination of whether procurement costs associated with these contracts are within the benchmark is done on a portfolio basis including a hypothetical cost for the Utility’s own generation facilities. Costs that are above the benchmark are recoverable as above-market generation and procurement costs. The Utility has asked the CPUC to approve an additional proposed revenue requirement of approximately $150 million to recover the 2004 costs related to the above-market generation and procurement costs that exceed the CPUC-adopted benchmark discussed above.

On January 26, 2004, the Utility filed with the CPUC revised electricity rates to implement rate changes based on the Utility’s overall revenue requirements for 2004. If this filling and related filings are approved, the ERRA would track and allow recovery of the difference between actual ERRA revenues collected and actual costs incurred.

Although the CPUC has no authority to review the reasonableness of procurement costs in the DWR’s contracts, it may review the Utility’s administration of the DWR allocated contracts. The Utility is required to dispatch its electricity resources, including the DWR allocated contracts, on a least-cost basis. The CPUC has established a maximum annual procurement disallowance 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, or $36 million for 2003. Activities excluded from the maximum annual disallowance include fuel expenses for the Utility’s electricity generation resources and contract administration costs associated with electricity procurement contracts, qualifying facility contracts and certain electricity generation expenses. In its decision approving the Utility’s 2004 short-term procurement plan, the CPUC extended the application of this maximum disallowance amount to cover the Utility’s 2004 procurement activities. It is uncertain whether the CPUC will modify or eliminate the maximum annual disallowance for future years.

Various entities, including the Utility and the State of California, are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from January 2000 to June 2001. In December 2002, a FERC administrative law judge issued an initial decision finding that power suppliers overcharged the utilities, the State of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001 (the only time period for which the FERC permitted refund claims), but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

During 2003, the FERC confirmed most of the administrative law judge’s findings, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX, which operates solely to reconcile remaining refund amounts owed, to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by August 2004. The actual refunds will not be determined until the FERC issues a final decision following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in this proceeding. In addition, future refunds could increase or decrease as a result of an alternative calculation proposed by the ISO, which incorporates revised data provided by the Utility and other entities.

Under the Settlement Agreement, the Utility and PG&E Corporation agreed to continue to cooperate with the CPUC and the State of California in seeking refunds from generators and other energy suppliers. The net after-tax amount of any refunds, claim offsets or other credits from generators or other energy suppliers relating to the Utility’s ISO, PX, qualifying facilities or energy service provider costs that are actually realized in cash or by offset of creditor claims in its Chapter 11 proceeding would reduce the balance of the $2.21 billion after-tax regulatory asset created by the Settlement Agreement.

The Utility has recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. The Utility currently estimates that the claims filed would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the administrative law judge’s initial decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could further reduce the amount of the suppliers’ claims by several hundred million dollars. However, this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology.

On January 13, 2003, the Utility filed an application with the FERC requesting authority to recover approximately $545 million in annual electricity transmission retail revenue requirements for 2003. The January 13, 2003 proposed rates went into effect, subject to refund, on August 13, 2003 and remained in effect through December 31, 2003. The Utility has accrued approximately $26 million for potential refunds related to the period these rates were in effect.

The Utility filed an additional rate application with the FERC at the end of October 2003 requesting recovery of approximately $530 million per year, subject to refund, in electricity transmission retail revenue requirements. The Utility requested a 13.0% return on equity and recovery of the costs of providing safe and reliable transmission service during 2004. On December 30, 2003 the FERC accepted this proposed revenue requirement and related rates, subject to hearing and refund, effective as of January 1, 2004.

In 1998, the Utility implemented a ratemaking pact called the Gas Accord under which the natural gas transportation and storage services the Utility provides were separated for ratemaking purposes from the Utility’s distribution services. On December 18, 2003, the CPUC approved the Utility’s application to retain the Gas Accord market structure for 2004 and 2005 and resolved the rates, and terms and conditions of service for the Utility’s natural gas transportation and storage system for 2004. The CPUC adopted a 2004 revenue requirement of $436.4 million, representing a $12.5 million increase from 2003.

In addition, the December 2003 CPUC decision exempts, beginning in 2005, certain customers connected to the Utility’s backbone transportation facilities from paying local transportation rates and orders the Utility to review and consider a backbone level rate structure, which may include a surcharge to recover what may otherwise be stranded costs resulting from departing local transmission customers. The Utility’s backbone transportation facilities connect natural gas transportation pipelines delivering natural gas from California’s border and from California production and storage facilities to the local natural gas transportation system.

Under the Gas Accord market structure, the Utility is at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account provisions for over-collections or under-collections of natural gas transportation or storage revenues. The Utility may experience a material reduction in operating revenues if throughput levels or market conditions are significantly less favorable than reflected in rates for these services.

The Gas Accord also established an incentive mechanism for recovery of core procurement costs, or the CPIM, which is used to determine the reasonableness of the Utility’s costs of purchasing natural gas for its customers. The December 2003 CPUC decision extended the CPIM with adjustments through 2005. Under the CPIM, the Utility’s purchase costs are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is currently 99% to 102% of the benchmark, are considered reasonable and fully recoverable in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in the Utility’s

On January 22, 2004 the CPUC opened a rulemaking to require California natural gas utilities to submit proposals aimed at ensuring reliable, long-term supplies of natural gas to California. The CPUC ordered the Utility and other California natural gas utilities to submit proposals addressing how California’s long-term natural gas needs should be met through contracts with interstate pipelines, new liquefied natural gas facilities, storage facilities and in-state production of natural gas. This proceeding will be divided into two phases. Phase 1 will address utilities’ expiring contracts with interstate pipelines, the amount of interstate capacity the utilities should hold, the approval process for contracts with interstate pipelines and access to liquefied natural gas facilities supplies. Phase 2 will examine broader long-term supply and capacity issues. The Utility is unable to predict the outcome of this rulemaking or the impact it will have on its financial condition or results of operations.

Annual Earnings Assessment Proceeding for Energy Efficiency Program Activities and Public Purpose Programs

In May 2003, 2002, 2001 and 2000, the Utility filed its annual applications with the CPUC claiming incentives totaling approximately $106 million in the Annual Earnings Assessment Proceeding for energy efficiency program activities and public purpose programs. These applications remain subject to verification and approval by the CPUC. The CPUC has only authorized the Utility to recognize an insignificant amount of these incentives in its consolidated statements of operations. There are a number of forward-looking proceedings regarding program administration and incentive mechanisms for energy efficiency. It is too early to predict whether the CPUC will allow the Utility to continue administering energy efficiency programs and earning incentives based on the performance of the programs.

2001 Annual Transition Cost Proceeding: Review of Reasonableness of Electricity Procurement

In April 2003, the ORA issued a report regarding the Utility’s procurement activities for the period July 1, 2000 through June 30, 2001, recommending that the CPUC disallow recovery of approximately $434 million of the Utility’s procurement costs based on an allegation that the Utility’s market purchases during the period were imprudent because they did not develop and execute a reasonable hedging strategy. The ORA recommendation does not take into account any FERC-ordered refunds of the Utility’s procurement costs during this period, which could effectively reduce the amount of the recommended disallowance. In the Utility’s response to the ORA’s report, the Utility indicated that the ORA recommendation is unlawful, contrary to prior CPUC decisions, and factually unsupported. Under the Settlement Agreement, the CPUC would agree to act promptly to resolve this proceeding, with no adverse impact on the Utility’s cost recovery, as soon as practicable after the Plan of Reorganization becomes effective.

The Utility and PG&E Corporation, mainly through its ownership of the Utility, are exposed to market risk, which is the risk that changes in market conditions will adversely affect net income or cash flows. PG&E Corporation and the Utility face market risk associated with their operations, financing arrangements, the marketplace for electricity, natural gas, electricity transmission, natural gas transportation and storage, other goods and services, and with other aspects of their business. PG&E Corporation and the Utility categorize market risks as price risk, interest rate risk and credit risk. The Utility actively manages market risks through risk management programs that are designed to support business objectives, reduce costs, discourage unauthorized risk, reduce earnings volatility and manage cash flows. The Utility’s risk management activities often include the use of energy and financial derivative instruments, including forward contracts, futures, swaps, options, and other instruments and agreements.

The Utility uses derivative instruments only for non-trading purposes (i.e., risk mitigation) and not for speculative purposes. The Utility uses derivative instruments to mitigate the risks associated with ownership of assets, liabilities, committed transactions or probable forecasted transactions. The Utility enters into derivative instruments in accordance with approved risk management policies adopted by a risk oversight committee composed of senior officers and only after the risk oversight committee approves appropriate risk limits for each derivative instrument. The organizational unit proposing the activity must successfully demonstrate that the derivative instrument satisfies a business need and that the attendant risks will be adequately measured, monitored and controlled.

The Utility estimates fair value of derivative instruments using the midpoint of quoted bid and asked forward prices, including quotes from customers, brokers, electronic exchanges and public indices, supplemented by online price information from news services. When market data is not available the Utility uses models to estimate fair value.

Because NEGT’s financial results are no longer consolidated with those of PG&E Corporation, NEGT’s market risks do not impact PG&E Corporation’s net income and cash flows.

The Utility relies on electricity from a diverse mix of resources, including third party contracts, amounts allocated under DWR contracts and its own electricity generation facilities. On January 1, 2003, the Utility resumed responsibility for purchasing electricity to meet its residual net open position. The Utility has purchased electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead) since that date.

It is estimated that the residual net open position will increase over time for a number of reasons, including:


	•	Periodic expirations of existing electricity purchase contracts;

	•	Periodic expirations or other terminations of the DWR allocated contracts;

	•	Increases in the Utility’s customers’ electricity demands due to customer and economic growth or other factors; and

	•	Retirement or closure of the Utility’s generation facilities.

In addition, unexpected outages at the Utility’s Diablo Canyon power plant or any of the Utility’s other significant generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility’s residual net open position. The Utility expects to satisfy at least some of the residual net open position through new contracts.

The Settlement Agreement contemplates that the Utility will recover its reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, or order refunds when there is an under- or over-collection exceeding 5% of the Utility’s prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR. In addition, the CPUC has established a maximum procurement disallowance of approximately $36 million for the Utility’s administration of the DWR contracts and least-cost dispatch. Adverse market price changes are not expected to impact the Utility’s net income, while these cost recovery regulatory mechanisms remain in place. However, the Utility is at risk to the extent that the CPUC may in the future disallow transactions that do not comply with the CPUC-approved short-term procurement plan. Additionally, adverse market price changes could impact the timing of the Utility’s cash flows.

The Utility purchases nuclear fuel for Diablo Canyon through contracts with terms ranging from two to five years. These agreements are with large, well-established international producers for its long-term nuclear fuel agreements in order to diversify its commitments and ensure security of supply.

Nuclear fuel purchases are subject to tariffs of up to 50% on imports from certain countries. The Utility’s nuclear fuel costs have not increased based on the imposed tariffs because the terms of the Utility’s existing long-term contracts do not include these costs. However, once these contracts begin to expire in 2004, the costs under new nuclear fuel contracts may increase. While the cost recovery regulatory mechanisms under California law described above remain in place, adverse market changes in nuclear fuel prices are not expected to materially impact net income.

The Utility enters into physical and financial natural gas commodity contracts of up to one-and-a-half years in length to fulfill the needs of its retail core customers. Changes in temperature cause natural gas demand to vary daily, monthly and seasonally. Consequently, significant volumes of gas must be purchased in the spot market. To mitigate the risk of price volatility, the Utility enters into various financial instruments, including options that may extend for up to five months in length. The Utility’s cost of natural gas includes the cost of Canadian and interstate transportation of natural gas purchased for its core customers.

Under the CPIM, the Utility’s purchase costs are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive three-fourths of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark, in their rates. While this cost recovery mechanism remains in place changes in the price of natural gas are not expected to materially impact net income.

The Utility currently faces price risk for the portion of intrastate natural gas transportation capacity that is not used by core customers. Non-core customers contract with the Utility for natural gas transportation and storage, along with natural gas parking and lending (market center) services. The Utility is at risk for any natural gas transportation and storage revenue volatility. Transportation is sold at competitive market-based rates within a cost-of-service tariff framework. There are significant seasonal and annual variations in the demand for natural gas transportation and storage services. The Utility sells most of its pipeline capacity based on the volume of natural gas that is transported by its customers. As a result, the Utility’s natural gas transportation revenues fluctuate.

The Utility uses a value-at-risk methodology to measure the expected maximum daily change in the 18-month forward value of its transportation and storage portfolio. The value-at-risk provides an indication of the Utility’s exposure to potential high-risk market conditions, and market opportunities for improved revenues based on price changes, high-price volatility or correlation between pricing locations. It is also an important indicator of the effectiveness of hedge strategies on a portfolio. The value-at-risk methodology is based on a 95% confidence level, which means that there is a 5% probability that the portfolio will incur a loss in value in one day at least as large as the reported value-at-risk. The one-day liquidation period assumption of the value-at-risk methodology does not match the longer-term holding period of the Utility’s transportation and storage contract portfolio.

The Utility’s value-at-risk for its transportation and storage portfolio was approximately $4.2 million at December 31, 2003 and approximately $4 million at December 31, 2002. A comparison of daily values-at-risk is included in order to provide context around the one-day amounts. The Utility’s high, low and average transportation and storage value-at-risk during 2003 was approximately $12.8, $1.7 and $5.4 million, respectively.

Value-at-risk has several limitations as a measure of portfolio risk, including, but not limited to, underestimation of the risk of a portfolio with significant options exposure, volumetric risk, inadequate indication of the exposure of a portfolio to extreme price movements and the inability to address the risk resulting from intra-day trading activities.

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for PG&E Corporation and the Utility include the risk of increasing interest rates on variable rate obligations.

Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At December 31, 2003, if interest rates changed by 1% for all current variable rate debt held by PG&E Corporation and the Utility, the change would affect net income by an immaterial amount, based on net variable rate debt and other interest rate-sensitive instruments outstanding.

As discussed above the Utility plans to issue long-term debt and establish credit facilities to facilitate payment of allowed claims in the Utility’s Chapter 11 proceeding. The Utility entered into derivative instruments, which expire in June 2004, to partially hedge the interest rate risk on up to $7.4 billion of the long-term debt to be issued.

The hedges are reflected on the balance sheet at fair value in other current assets. The cost of the hedges, purchased at fair value, was approximately $45 million. The fair value of the hedges at December 31, 2003 was approximately $17 million. At December 31, 2003, a hypothetical 1% decrease in interest rates would cause the fair value of the interest rate hedges to fall below $1 million; however, the change in fair value of the interest rate hedges would primarily be reported in regulatory accounts, and would be offset by changes in interest expense once the forecasted debt is issued.

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if customers or counterparties failed to perform their contractual obligations.

PG&E Corporation had gross accounts receivable of approximately $2.5 billion at December 31, 2003 and approximately $2.0 billion at December 31, 2002. The majority of the accounts receivable are associated with the Utility’s residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $68 million at December 31, 2003 and approximately $59 million at December 31, 2002 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered likely.

The Utility manages credit risk for its largest customers and counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for the Utility’s largest customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure or obtain additional collateral, or both. Further, the Utility relies heavily on master agreements that require security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

The Utility calculates gross credit exposure for each of its largest customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, before the application of credit collateral. During 2003, the Utility recognized no material losses due to contract defaults or bankruptcies. At December 31, 2003, there were three counterparties that represented greater than 10% of the Utility’s net credit exposure. The Utility had two investment grade counterparties that represented a total of approximately 32% of the Utility’s net credit exposure and one below-investment grade counterparty that represented approximately 12% of the Utility’s net credit exposure.

The Utility conducts business with customers or vendors mainly in the energy industry, including other California investor-owned electric utilities, municipal utilities, energy trading companies, financial institutions, and oil and natural gas production companies located in the United States and Canada. This concentration of counterparties may impact the Utility’s overall exposure to credit risk because counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions.

The preparation of Consolidated Financial Statements in accordance with GAAP involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The accounting policies described below are considered to be critical accounting policies due, in part, to their complexity and because their application is relevant and material to the financial position and results of operations of PG&E Corporation and the Utility, and because these policies require the use of material judgments and estimates. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.

The Utility acts as a pass-through entity for electricity purchased by the DWR that is sold to the Utility’s customers. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts from electricity revenues amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers, priced at the related CPUC-approved remittance rate. These pass-through amounts are excluded from the Utility’s electricity revenues in its Consolidated Statements of Operations. During 2003, 2002 and 2001, the pass-through amounts have been subject to significant adjustments.

On January 26, 2004, the Utility filed with the CPUC revised electricity rates to implement all rate changes based on the Utility’s overall revenue requirements for 2004. If approved, the new rates will be effective March 1,

2004, and the resultant revenue reduction will be retroactive to January 1, 2004. Because the DWR’s revenue requirements will be included as a component of the Utility’s total rates in 2004, these DWR revenue requirements, and any related adjustments, will result in adjustment to the Utility’s electricity rates and are not expected to impact the Utility’s future results of operations or financial position.

The DWR’s revenue requirements are subject to various adjustments, including the reallocation of DWR contracts among the California investor-owned electric utilities, adjustments to actual deliveries and changes in allocation methodologies. In January 2004, the CPUC issued a decision finding that the Utility over-remitted approximately $101 million in power charges to the DWR related to the DWR’s 2001-2002 revenue requirement and ordered that the Utility’s allocation of the DWR’s 2004 revenue requirement to the customers of the California investor-owned electric utilities be reduced by this amount.

PG&E Corporation and the Utility apply SFAS No. 71 to their regulated operations. Under SFAS No. 71, regulatory assets represent capitalized costs that otherwise would be charged to expense under GAAP. These costs are later recovered through regulated rates. Regulatory liabilities are created by rate actions of a regulator that will later be credited to customers through the ratemaking process. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, administrative law judge proposed decisions, final regulatory orders and the strength or status of applications for regulatory rehearings or state court appeals. The Utility also maintains regulatory balancing accounts, which are comprised of sales and cost balancing accounts. These balancing accounts are used to record the differences between revenues and costs that are recorded and that can be recovered through rates.

If it is determined that a regulatory asset is no longer probable of recovery in rates, then SFAS No. 71 requires that it be written off at that time. At December 31, 2003 PG&E Corporation reported regulatory assets (including current regulatory balancing accounts receivable) of approximately $2.2 billion and regulatory liabilities (including current balancing accounts payable) of approximately $4.2 billion.

The Utility expects to recognize the regulatory assets created by the Settlement Agreement when they meet the probability requirements of SFAS No. 71. Implementation of the Plan of Reorganization is subject to various conditions, including the consummation of the public offering of long-term debt, the receipt of investment grade credit ratings and final CPUC approval of the Settlement Agreement. Under the terms of the Plan of Reorganization PG&E Corporation and the Utility may determine that the CPUC order approving the Settlement Agreement is final even if appeals are pending. There can be no assurance that the Settlement Agreement will not be modified on rehearing or appeal or that the Plan of Reorganization will become effective. Until certain conditions or events regarding the effectiveness of the Plan of Reorganization discussed above are resolved further, the Utility cannot conclude that it has met the probability requirements of SFAS No. 71 and therefore cannot record the regulatory assets contemplated in the Settlement Agreement.

The Utility records revenue as electricity and natural gas are delivered. A portion of the revenue recognized has not yet been billed. Unbilled revenues are determined by factoring an estimate of the electricity and natural gas load delivered with recent historical usage and rate patterns.

In January 2001, the CPUC authorized increases in electricity rates of $0.01 per kWh, in March 2001 of another $0.03 per kWh and in May 2001 of an additional $0.005 per kWh. The use of these surcharge revenues was initially restricted to “ongoing procurement costs” and “future power purchases.” In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the surcharges to be used to restore the Utility’s financial health by permitting the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. From January 2001 to December 31, 2003, the Utility recognized total surcharge revenues of approximately $8.1 billion, pre-tax. The rate design settlement includes a refund of approximately $125 million of surcharge revenues. Accordingly, at December 31, 2003, the Utility has recorded a regulatory liability for the potential refund of approximately $125 million of surcharge revenues collected during 2003. In addition, if the CPUC requires the Utility to refund any amounts in excess of $125 million, the Utility’s earnings could be materially adversely affected.

Given the complexities of the legal and regulatory environment regarding environmental laws, the process of estimating environmental remediation liabilities is a subjective one. The Utility records a liability associated with environmental remediation activities when it is determined that remediation is probable and its cost can be estimated in a reasonable manner. The liability can be based on many factors, including site investigations, remediation, operations, maintenance, monitoring and closure. This liability is recorded at the lower range of estimated costs, unless a more objective estimate can be achieved. The recorded liability is re-examined every quarter.

At December 31, 2003 the Utility’s undiscounted environmental liability was approximately $314 million, which was approximately $17 million lower than at December 31, 2002, mainly due to a reassessment of the estimated cost of remediation and remediation payments. The Utility’s undiscounted future costs could increase to as much as $422 million if other potentially responsible parties are not able to contribute to the settlement of these costs, the extent of contamination or necessary remediation is greater than anticipated or the Utility is found to be responsible for additional clean-up costs.

In 2001, PG&E Corporation and the Utility adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, or SFAS No. 133, which required all derivative instruments to be recognized in the financial statements at their fair value.

The Utility has long-term purchase contracts, including power purchase and renewable energy, natural gas supply and transportation, and nuclear fuel as reflected in “Capital Expenditures and Commitments” discussed above. The Utility has determined most of these contracts, including substantially all of its qualifying facility and nuclear fuel contracts, are not derivative instruments. Most of the remaining contracts that are derivative instruments are exempt from the mark-to-market requirements of SFAS No. 133 under the normal purchases and sales exception and are not reflected on the balance sheet at fair value. In addition, the Utility holds derivative instruments that are used to offset natural gas commodity price risk and interest rate risk. These instruments qualify for cash flow hedge treatment under SFAS No. 133 and are presented on the balance sheet at fair value, which amounted to approximately $21 million at December 31, 2003.

Certain employees and retirees of PG&E Corporation and its subsidiaries participate in qualified and non-qualified non-contributory defined benefit pension plans. Certain retired employees and their eligible dependents of PG&E Corporation and its subsidiaries also participate in contributory medical plans, and certain retired employees participate in life insurance plans (referred to collectively as other benefits). Amounts that PG&E Corporation and the Utility recognize as obligations to provide pension benefits under SFAS No. 87, “Employers’ Accounting for Pensions,” and other benefits under SFAS No. 106, “Employers Accounting for Postretirement Benefits other than Pensions,” are based on certain actuarial assumptions. Actuarial assumptions used in determining pension obligations include the discount rate, the average rate of future compensation increases and the expected return on plan assets. Actuarial assumptions used in determining other benefit obligations include the discount rate, the average rate of future compensation increases, the expected return on plan assets and the assumed health care cost trend rate. While PG&E Corporation and the Utility believe the assumptions used are appropriate, significant differences in actual experience, plan changes or significant changes in assumptions may materially affect the recorded pension and other benefit obligations and future plan expenses.

Pension and other benefit funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for pension and other benefit payments. Consistent with the trusts’ investment policies, assets are invested in U.S. equities, non-U.S. equities and fixed income securities. Investment securities are exposed to various risks, including interest rate, credit and overall market volatility risks. As a result of these risks, it is reasonably possible that the market values of investment securities could increase or decrease in the near term. Increases or decreases in market values could materially affect the current value of the trusts and, as a result, the future level of pension and other benefit expense.

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income projected returns were based on historical returns for the broad U.S. bond market. Equity returns were based primarily on historical returns of the S&P 500 Index. For the Utility Retirement Plan, the assumed return of 8.1% compares to a ten-year actual return of 8.5%.

The rate used to discount pension and other post-retirement benefit plan liabilities was based on a yield curve developed from the Moody’s AA Corporate Bond Index at December 31, 2003. This yield curve has discount rates that vary based on the maturity of the obligations. The estimated future cash flows for the pension and other post retirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. For the Utility Retirement Plan, a decrease in the discount rate from 6.25% to 6.00% would increase the accumulated benefit obligation by approximately $202 million.

Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003

In January 2004, the Financial Accounting Standards Board, or FASB, issued FASB Staff Position SFAS No. 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003,” or SFAS No. 106-1. SFAS No. 106-1 permits a sponsor to make a one-time election to defer accounting for the effects of the Medicare Prescription Drug, Improvement and Modernization Act of 2003, or the Prescription Drug Act. The Prescription Drug Act, signed into law in December 2003, establishes a prescription drug benefit under Medicare (Medicare Part D) and a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. SFAS No. 106-1 does not provide specific guidance as to whether a sponsor should recognize the effects of the Prescription Drug Act in its financial statements. The Prescription Drug Act introduces two new features to Medicare that must be considered when measuring accumulated postretirement benefit costs. The new features include a subsidy to the plan sponsors that is based on 28% of an individual beneficiary’s annual prescription drug costs between $250 and $5,000 and an opportunity for a retiree to obtain a prescription drug benefit under Medicare. The Prescription Drug Act is expected to reduce PG&E Corporation’s net postretirement benefit costs.

PG&E Corporation and the Utility have elected to defer adoption of SFAS No. 106-1 due to the lack of specific guidance. Therefore, the net postretirement benefit costs disclosed in PG&E Corporation’s and the Utility’s Consolidated Financial Statements do not reflect the impacts of the Prescription Drug Act on the plans. The deferral will continue to apply until specific authoritative accounting guidance for the federal subsidy is issued. Authoritative guidance on the accounting for the federal subsidy is pending and, when issued, could require information previously reported in PG&E Corporation’s and the Utility’s Consolidated Financial Statements to change. PG&E Corporation and the Utility are currently investigating the impacts of SFAS 106-1’s initial recognition, measurement and disclosure provisions on their Consolidated Financial Statements.

In November 2003 the FASB approved an amendment to an interpretation issued by the Derivatives Implementation Group C15, (as previously amended in October 2001 and December 2001, or DIG C15), that changed the definition of normal purchases and sales for certain power contracts that contain optionality.

The implementation guidance in DIG C15 impacts certain derivative instruments entered into after June 30, 2003. Prior to this amendment to DIG C15, most of the Utility’s derivative instruments have qualified for the normal purchases and sales exception. However, it is possible that new derivative instruments and certain of the Utility’s derivative instruments entered into prior to July 1, 2003 will no longer qualify for normal purchases and sales treatment under the new guidelines of DIG C15. Application of the new guidance to existing derivative instruments that were eligible for the normal purchases and sales exception under the previous DIG C15 guidance will be effective in the first quarter of 2004 as a cumulative effect of a change in accounting principle. PG&E Corporation and the Utility are currently evaluating the impacts, if any, of DIG C15 on their Consolidated Financial Statements.

In December 2003, the FASB issued Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” or FIN 46R, replacing Interpretation No. 46, “Consolidation of Variable Interest Entities,” or FIN 46, which was issued in January 2003. FIN 46R was issued to replace FIN 46 and to clarify the required accounting for interests in variable interest entities. A variable interest entity is an entity that does not have sufficient equity investment at risk, or the holders of the equity instruments lack the essential characteristics of a controlling financial interest. A variable interest entity is to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities, or is entitled to receive a majority of the entity’s residual returns, or both.

PG&E Corporation and the Utility must apply the provisions of FIN 46R as of January 1, 2004. PG&E Corporation and the Utility are continuing to evaluate the impacts of FIN 46R’s initial recognition, measurement and disclosure provisions on their Consolidated Financial Statements and are unable to estimate the impact, if any, which will result when FIN 46R becomes effective. The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of low-income residential real estate property. It is reasonably possible that the Utility will be required to consolidate its interests in these entities as a result of the adoption of FIN 46R. At December 31, 2003 the Utility’s recorded investment in these entities was approximately $21 million. As a limited partner, the Utility’s exposure to potential loss is limited to its investment in each partnership.

The IRS has completed its audit of PG&E Corporation’s 1997 and 1998 consolidated federal income tax returns and has assessed additional federal income taxes of $74 million (including interest). PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and currently is discussing these adjustments with the IRS’ Appeals Office.

The IRS also is auditing PG&E Corporation’s 1999 and 2000 consolidated federal income tax returns, but has not issued its final report. In the fourth quarter of 2003, PG&E Corporation made an advance payment to the IRS of $75 million to halt the accrual of interest in respect of these tax returns. The assessment and payment did not have a material effect on PG&E Corporation’s financial position or results of operations.

As a result of NEGT’s Chapter 11 filing on July 8, 2003, the IRS recently began its audit of PG&E Corporation’s 2001 and 2002 consolidated federal income tax returns. On June 27, 2003 the IRS announced it will review scientific tests related to production of synthetic fuels. A partnership owned by NEGT subsidiaries operated two synthetic fuel facilities in 2001 and most of 2002. PG&E Corporation has claimed tax credits totaling approximately $104 million for these facilities. If the IRS determines that these synthetic fuel facilities do not meet the criteria to qualify for the tax credit, PG&E Corporation may be subject to additional tax and interest. All of PG&E Corporation’s federal income tax returns prior to 1997 have been closed. In addition, California and certain other state tax authorities currently are auditing various state tax returns.

In 2003, PG&E Corporation increased its valuation allowance against certain state deferred tax assets related to NEGT or its subsidiaries due to the uncertainty in their realization. Valuation allowances of approximately $24 million were recorded in discontinued operations, and approximately $5 million in accumulated other comprehensive loss for 2003.

PG&E Corporation will not recognize additional income tax benefits for financial statement reporting purposes after July 7, 2003 with respect to any subsequent losses related to NEGT or its subsidiaries even though it continues to include NEGT and its subsidiaries in its consolidated income tax returns. Any such unrecognized benefits and deferred tax assets arising from losses related to NEGT or its subsidiaries that have been recognized through July 7, 2003 will be recorded in discontinued operations in the Consolidated Statements of Operations at the time that PG&E Corporation releases its ownership interest in NEGT.

NEGT and its creditors have brought litigation against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT’s Board of Directors, in NEGT’s Chapter 11 proceeding, asserting, among other claims, that NEGT is entitled to be compensated under an alleged tax sharing agreement between PG&E Corporation and NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of the losses and deductions related to NEGT or it subsidiaries in PG&E Corporation’s consolidated federal tax return. This litigation is discussed above.

The NRC issued orders in 2003 regarding additional security measures for all nuclear plants, including the Utility’s Diablo Canyon power plant. These orders require additional capital investment and increased operating costs. However, neither PG&E Corporation nor the Utility believes these costs will have a material impact on its consolidated financial position or results of operation.

PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, electricity transmission, and natural gas transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. The Utility served approximately 4.9 million electricity distribution customers and approximately 3.9 million natural gas distribution customers at December 31, 2003. Both PG&E Corporation and the Utility are headquartered in San Francisco, California.

As discussed further in Note 2, on April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the federal Bankruptcy Code, or Bankruptcy Code, in the U.S. Bankruptcy Court for the Northern District of California. The Utility retained control of its assets and is authorized to operate its business as a debtor-in-possession during its Chapter 11 proceeding.

PG&E Corporation’s other significant subsidiary is National Energy & Gas Transmission, Inc., formerly known as PG&E National Energy Group, Inc., or PG&E NEG, headquartered in Bethesda, Maryland. PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, PG&E NEG and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. Subsequently, on July 29, 2003, two additional subsidiaries of PG&E NEG also filed voluntary Chapter 11 petitions. PG&E NEG and those subsidiaries in Chapter 11 retain control of their assets and are authorized to operate their businesses as debtors-in-possession while being subject to the jurisdiction of the bankruptcy court. On October 3, 2003, the bankruptcy court authorized PG&E NEG to change its name to National Energy & Gas Transmission, Inc., or NEGT. The change reflects NEGT’s pending separation from PG&E Corporation. Consequently, all subsequent references to PG&E NEG in these Notes to the Consolidated Financial Statements will refer to NEGT. NEGT’s proposed plan of reorganization if implemented, would eliminate PG&E Corporation’s equity interest in NEGT.

Under accounting principles generally accepted in the United States of America, or GAAP, consolidation is generally required for investments of more than 50% of the outstanding voting stock of an investee, except when control is not held by the majority owner. Under these rules, legal reorganization and bankruptcy represent conditions that can preclude consolidation in instances where control rests with an entity other than the majority owner. In anticipation of NEGT’s Chapter 11 filing, PG&E Corporation’s representatives, who previously served on the NEGT Board of Directors, resigned on July 7, 2003 and were replaced with Board members who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT. PG&E Corporation anticipates that the bankruptcy court will approve NEGT’s proposed plan of reorganization, or a plan with similar equity elimination provisions for PG&E Corporation. Therefore, effective July 8, 2003, PG&E Corporation no longer consolidates the earnings and losses of NEGT or its subsidiaries and has reflected its ownership interest in NEGT utilizing the cost method of accounting, under which PG&E Corporation’s investment in NEGT is reflected as a single amount on the Consolidated Balance Sheet of PG&E Corporation at December 31, 2003. In addition, for the reasons described above, PG&E Corporation considers NEGT to be an abandoned asset under Statement of Financial Accounting Standards, or SFAS, “Accounting for Impairment or Disposal of Long-Lived Assets,” or SFAS No. 144, and, as a result, the operations of NEGT prior to July 8, 2003 and for all prior years, are reflected as discontinued operations in the Consolidated Financial Statements (see Note 5 for further information).

This is a combined annual report of PG&E Corporation and the Utility. Therefore, the Notes to the Consolidated Financial Statements apply to both PG&E Corporation and the Utility. PG&E Corporation’s Consolidated Financial Statements include the accounts of PG&E Corporation, the Utility, and other wholly owned and controlled subsidiaries. The Utility’s Consolidated Financial Statements include its accounts and those of its wholly owned and controlled subsidiaries. All significant intercompany transactions have been eliminated from the Consolidated Financial Statements.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets and liabilities

and the disclosure of contingencies. As these estimates involve judgments on a wide range of factors, including future economic conditions that are difficult to predict, actual results could differ from these estimates.

Accounting principles used include those necessary for rate-regulated enterprises, which reflect the financial impact of ratemaking policies of the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

PG&E Corporation’s and the Utility’s Consolidated Financial Statements have been prepared in accordance with the American Institute of Certified Public Accountants’ Statement of Position 90-7, “Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” or SOP 90-7, and on a going-concern basis, which contemplates continuity of operation, realization of assets, and liquidation of liabilities in the ordinary course of business. As a result of the Utility’s Chapter 11 filing, the realization of assets and liquidation of liabilities are subject to uncertainty. Under SOP 90-7, certain claims against the Utility existing before the Utility’s Chapter 11 filing are classified as liabilities subject to compromise on PG&E Corporation’s and the Utility’s Consolidated Balance Sheets. Additionally, professional fees and expenses directly related to the Utility’s Chapter 11 proceeding and interest income on funds accumulated during the Chapter 11 proceedings are reported separately as reorganization items. Finally, the extent to which the Utility’s reported interest expense differs from its stated contractual interest is disclosed on the Utility’s Consolidated Statements of Operations.

Certain amounts in the 2002 and 2001 Consolidated Financial Statements have been reclassified to conform to the 2003 presentation. These reclassifications did not affect the consolidated net income reported by PG&E Corporation and the Utility for the periods presented.

Basic earnings (loss) per share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during the period. Diluted earnings (loss) per share is computed by dividing net income (loss), adjusted for the net interest and amortization associated with PG&E Corporation’s Convertible Subordinated Notes, by the sum of the weighted average number of common shares outstanding and the assumed issuance of common shares for all dilutive securities.

The following is a reconciliation of PG&E Corporation’s net income (loss) and weighted average common shares outstanding for calculating basic and diluted net income (loss) per share:

PG&E Corporation reflects the preferred dividends of its subsidiary as other expense for computation of both basic and diluted earnings per share.

The accounting policies used by PG&E Corporation and the Utility include those necessary for rate-regulated enterprises, which reflect the ratemaking policies of the CPUC or the FERC.

In December 2003, the Financial Accounting Standards Board, or the FASB, issued Interpretation No. 46 (revised December 2003), “Consolidation of Variable Interest Entities,” or FIN 46R, replacing Interpretation No. 46, “Consolidation of Variable Interest Entities,” or FIN 46, which was issued in January 2003. FIN 46R was issued to replace FIN 46, and to clarify the required accounting for interests in variable interest entities. A variable interest entity is an entity that does not have sufficient equity investment at risk, or the holders of the equity instruments lack the essential characteristics of a controlling financial interest. A variable interest entity is to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities, or is entitled to receive a majority of the entity’s residual returns, or both.

PG&E Corporation and the Utility must apply the provisions of FIN 46R as of January 1, 2004. PG&E Corporation and the Utility are continuing to evaluate the impacts of FIN 46R’s initial recognition, measurement and disclosure provisions on their Consolidated Financial Statements and are unable to estimate the impact, if any, which will result when FIN 46R becomes effective. The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of low-income residential real estate property. It is reasonably possible that the Utility will be required to consolidate its interests in these entities as a result of the adoption of FIN 46R. At December 31, 2003, the Utility’s recorded investment in these entities was approximately $21 million. As a limited partner, the Utility’s exposure to potential loss is limited to its investment in each partnership.

Reporting Realized Gains and Losses on Derivative Instruments Held for Non-Trading Purposes

On October 1, 2003, PG&E Corporation and the Utility adopted the Emerging Issues Task Force, or EITF, Issue No. 03-11, “Reporting Realized Gains and Losses on Derivative Instruments Not Held for Trading Purposes That Are Subject to FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” and Not Held for Trading Purposes as Defined in EITF Issue No. 02-3, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities.” Under EITF Issue No. 03-11, the determination of whether realized gains and losses on derivative instruments held

For all non-trading derivative instruments that do not qualify for cash flow hedge accounting treatment, PG&E Corporation and the Utility report both realized and unrealized gains and losses on a net basis in the Consolidated Statement of Operations. The financial reporting requirements reflected in EITF Issue No. 03-11 did not have any impact on the Consolidated Financial Statements of PG&E Corporation and the Utility, nor did they result in any reclassifications of revenues and expenses.

Amendment of Statement 133 on Derivative Instruments and Hedging Activities

On July 1, 2003, PG&E Corporation and the Utility adopted SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities,” or SFAS No. 149. SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including the criteria for qualifying for the normal purchases and sales exception, certain derivative instruments embedded in other contracts and for hedging activities. SFAS No. 149 also clarifies circumstances under which a contract with an initial net investment meets the characteristics of a derivative instrument according to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, or SFAS No. 133. The provisions of SFAS No. 149 that relate to SFAS No. 133 Implementation Issues that have been effective for periods that began prior to June 15, 2003 continue to be applied in accordance with their respective effective dates.

The requirements of SFAS No. 149 are effective for derivative instruments entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. The adoption of SFAS No. 149 did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

Accounting for Financial Instruments with Characteristics of Both Liabilities and Equity

In May 2003, the FASB issued Statement No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity,” or SFAS No. 150. SFAS No. 150 addresses concerns of how to measure and classify in the balance sheet certain financial instruments that have characteristics of both liabilities and equity. The following freestanding financial instruments must be classified as liabilities: mandatorily redeemable financial instruments, obligations to repurchase an issuer’s equity shares by transferring assets and certain obligations to issue a variable number of shares.

PG&E Corporation and the Utility adopted the requirements of SFAS No. 150 in the third quarter of 2003. As a result, the Utility reclassified approximately $137 million of preferred stock with mandatory redemption provisions as a noncurrent liability. The reclassification did not have an impact on earnings of PG&E Corporation or the Utility. Upon adopting SFAS No. 150, all amounts paid or to be paid to the holders of preferred stock with mandatory redemption provisions in excess of the initial measured amount are reflected in interest expense. Dividends paid or accrued in prior periods have not been reclassified.

In May 2003, the EITF reached consensus on EITF Issue No. 01-8, “Determining Whether an Arrangement Contains a Lease,” or EITF 01-8. EITF 01-8 establishes criteria to be applied to any new or modified agreement in order to ascertain if the agreement is in effect a lease and subject to lease accounting treatment and disclosure requirements principally found in SFAS No. 13, “Accounting for Leases”. EITF 01-8 is effective for all new or modified arrangements entered into as of July 1, 2003. The adoption of EITF 01-8 did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

PG&E Corporation incorporated the disclosure requirements of FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” or FIN 45, into its December 31, 2002 disclosure of guarantees. Beginning January 1, 2003, PG&E Corporation applied the initial recognition and measurement provisions of FIN 45 to guarantees issued or modified after December 31, 2002.

FIN 45 elaborates on existing disclosure requirements for most guarantees. It also clarifies that at the time a company issues a guarantee, it must recognize a liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that

The adoption of this interpretation did not have a material impact on the Consolidated Financial Statements of PG&E Corporation or the Utility.

On January 1, 2003, PG&E Corporation and the Utility adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” or SFAS No. 143. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible long-lived assets. SFAS No. 143 requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and costs recovered through the ratemaking process.


	•	The Utility identified its nuclear generation and certain fossil generation facilities as having asset retirement obligations as of January 1, 2003. No additional asset retirement obligations had been identified as of December 31, 2003. Through December 31, 2002, the Utility had recorded approximately $1.4 billion for its nuclear and fossil decommissioning obligations in accumulated depreciation in the Consolidated Balance Sheets;

	•	Upon adoption of SFAS No. 143, the Utility reclassified the decommissioning liabilities recorded through December 31, 2002 as asset retirement obligations in the Consolidated Balance Sheets. To record the decommissioning liabilities at fair value as required by SFAS No. 143, the Utility then reduced the asset retirement obligations by approximately $53 million. The Utility increased its property, plant and equipment balance by approximately $332 million to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, less accumulated depreciation from the date the obligation was incurred through December 31, 2002. Finally, the Utility recorded a regulatory liability of approximately $387 million to reflect the cumulative effect of adoption for its nuclear facilities. This regulatory liability represents timing differences between recognition of nuclear decommissioning obligations in accordance with GAAP and the expense recognized for ratemaking purposes. The cumulative effect of the change in accounting principle for the Utility’s fossil facilities as a result of adopting SFAS No. 143 was a loss of approximately $1 million, after-tax;

	•	In connection with an application filed with the CPUC requesting an increase in the Utility’s nuclear decommissioning revenue requirements for the years 2003 through 2005, during 2003 the Utility developed a new estimate for costs to decommission its nuclear facilities. As a result, the Utility reduced its asset retirement obligation by approximately $223 million from the amount recorded upon the Utility’s adoption of SFAS No. 143 on January 1, 2003. The Utility also reduced its property, plant and equipment balance by approximately $61 million. Finally, to account for timing differences between recognition of the modified asset retirement obligation as recorded in accordance with GAAP and ratemaking purposes, the Utility increased its regulatory liability by approximately $162 million;

If SFAS No. 143 had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the year ended December 31, 2002 would not have been material. The amounts recorded upon adoption of SFAS No. 143 reflect the pro forma effects on the Consolidated Balance Sheets had SFAS No. 143 been adopted on December 31, 2002;

The Utility has established trust funds that are legally restricted for purposes of settling its nuclear decommissioning obligations. The fair value and carrying value of these trust funds was approximately $1.4 billion at December 31, 2003 and approximately $1.3 billion at December 31, 2002;

The Utility may have potential asset retirement obligations under various land right documents associated with its transmission and distribution facilities. The majority of the Utility’s land rights are perpetual. Any non-perpetual land rights generally are renewed continuously because the Utility intends to utilize these facilities indefinitely. Since

The Utility collects estimated removal costs in rates through depreciation in accordance with regulatory treatment. These amounts do not represent SFAS No. 143 asset retirement obligations. Historically, these removal costs have been recorded in accumulated depreciation. However, as a result of recent guidance from the staff of the Securities and Exchange Commission, or SEC, the Utility reclassified this obligation to a regulatory liability in its December 31, 2003 balance sheet. The Utility’s estimated removal costs recorded as a regulatory liability were approximately $1.8 billion at December 31, 2003 and approximately $1.6 billion at December 31, 2002, recorded in accumulated depreciation.

On January 1, 2003, PG&E Corporation adopted SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” or SFAS No. 146. SFAS No. 146 supersedes previous accounting guidance, principally EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity,” or EITF 94-3. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF 94-3, a liability for an exit cost is recognized at the commitment date of an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. The adoption of SFAS No. 146 did not have any impact on the Consolidated Financial Statements of PG&E Corporation or the Utility at the date of adoption.

PG&E Corporation and the Utility had no goodwill on their Consolidated Balance Sheets at December 31, 2003 or 2002. Other intangible assets consist mainly of hydroelectric facility licenses and other agreements. The gross carrying amount of the hydroelectric facility licenses and other agreements was approximately $73 million at December 31, 2003 and $67 million at December 31, 2002. The accumulated amortization was approximately $19 million at December 31, 2003 and $16 million at December 31, 2002.

The Utility’s amortization expense related to intangible assets was approximately $3 million in 2003, $3 million in 2002 and $2 million in 2001. The estimated annual amortization expense for the Utility’s intangible assets for 2004 through 2008 is approximately $3 million.

Invested cash and other investments with original maturities of three months or less are considered cash equivalents. Cash equivalents are stated at cost, which approximates fair value. PG&E Corporation and the Utility primarily invest their cash in money market funds and in short-term obligations of the U.S. government and its agencies.

The Utility had account balances with Fiduciary Trust Company International that were greater than 10% of PG&E Corporation’s and the Utility’s total cash and cash equivalents balance at December 31, 2003.

Restricted cash includes deposits under certain third party agreements, amounts held in escrow as collateral required by the California Independent System Operator, or ISO, and other counterparties and deposits securing workers’ compensation obligations. In addition, certain amounts designated as restricted by management related to the tax dispute with NEGT and discussed in Note 12 are included within other noncurrent assets on PG&E Corporation’s Consolidated Balance Sheet at December 31, 2003.

Inventories include materials, supplies and gas stored underground that are valued at average cost.

PG&E Corporation and the Utility use the liability method of accounting for income taxes. Income tax expense (benefit) includes current and deferred income taxes resulting from operations during the year. Investment tax credits

PG&E Corporation files a consolidated U.S. (federal) income tax return that includes domestic subsidiaries in which its ownership is 80% or more. In addition, PG&E Corporation files combined state income tax returns where applicable. PG&E Corporation and the Utility are parties to a tax-sharing arrangement under which the Utility determines its income tax provision (benefit) on a stand-alone basis.

NEGT is included in the consolidated tax return of PG&E Corporation. As discussed in Note 12, NEGT and its creditors have filed a complaint against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT’s Board of Directors, asserting, among other claims, that NEGT is entitled to be compensated under an alleged tax sharing agreement between PG&E Corporation and NEGT for any tax savings achieved as a result of incorporation of losses, deductions and tax credits related to NEGT or its subsidiaries in PG&E Corporation’s consolidated federal tax returns. PG&E Corporation disputes this assertion.

The Utility has investments in unconsolidated affiliates, which are mainly engaged in the purchase of low-income residential real estate property. The equity method of accounting is applied to the Utility’s investment in these entities. Under the equity method, the Utility’s share of equity income or losses of these entities is reflected as equity in earnings of affiliates. As of December 31, 2003, the Utility’s recorded investment in these entities totaled approximately $21 million in accordance with the equity method of accounting. As a limited partner, the Utility’s exposure to potential loss is limited to its investment in each partnership.

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services to and from their parent, PG&E Corporation, and among themselves. The Utility and PG&E Corporation exchange administrative and professional services in support of operations. These services are priced either at the fully loaded cost (i.e., direct costs and allocations of overhead costs) or at the higher of fully loaded cost or fair market value, depending on the nature of the services. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using agreed allocation factors, including the number of employees, operating expenses excluding fuel purchases, total assets and other cost allocation methodologies. The Utility purchases natural gas transportation services from Gas Transmission Northwest Corporation, or GTNW, formerly known as PG&E Gas Transmission, Northwest Corporation. Effective April 1, 2003, the Utility no longer purchases natural gas from NEGT Energy Trading Holdings Corporation, or NEGT ET, formerly known as PG&E Energy Trading Holdings Corporation. Both GTNW and NEGT ET are subsidiaries of NEGT. The Utility sold natural gas transportation capacity and other ancillary services to NEGT ET until NEGT’s Chapter 11 proceeding was imminent. These services were priced at either tariff rates or fair market value, depending on the nature of the services provided. Through July 7, 2003, all significant intercompany transactions are eliminated in consolidation; therefore, no profit or loss resulted from these transactions. Beginning July 8, 2003, the Utility’s transactions with NEGT are no longer eliminated in consolidation. The Utility’s significant related party transactions and related receivable (payable) balances were as follows:

Property, plant and equipment are reported at their original cost, unless impaired under the provisions of SFAS No. 144. Original costs include:


	•	Labor and materials;

	•	Construction overhead; and

	•	Capitalized interest or an allowance for funds used during construction, or AFUDC.

Capitalized Interest and AFUDC – AFUDC is the estimated cost of debt and equity funds used to finance regulated plant additions that is allowed to be recorded as part of the costs of construction projects. AFUDC is recoverable from customers through rates once the property is placed in service. PG&E Corporation and the Utility had capitalized interest and AFUDC of approximately $29 million at December 31, 2003, $27 million at December 31, 2002 and $18 million at December 31, 2001.

Depreciation – The Utility’s composite depreciation rate was 3.42% in 2003, 3.42% in 2002 and 3.63% in 2001.

The useful lives of the Utility’s property, plant and equipment are authorized by the CPUC. Depreciation rates include a component for the cost of asset retirement net of salvage value. The Utility has a separate rate component for the accrual of its recorded obligation for nuclear decommissioning, which is included in depreciation, amortization and decommissioning expense in the accompanying Consolidated Statements of Operations.

PG&E Corporation charged the original cost of retired plant and removal costs less salvage value to accumulated depreciation upon retirement of plant in service for the Utility’s lines of business that apply SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” as amended, or SFAS No. 71, which include electricity and natural gas distribution, electricity transmission, and natural gas transportation and storage.

Nuclear Fuel – Property, plant and equipment also includes nuclear fuel inventories. Stored nuclear fuel inventory is stated at weighted average cost. Nuclear fuel in the reactor is amortized based on the amount of energy output.

Capitalized Software Costs – PG&E Corporation capitalizes costs incurred during the application development stage of internal use software projects to property, plant and equipment. Capitalized software costs totaled $273 million at December 31, 2003 and $303 million at December 31, 2002, net of accumulated amortization of approximately $159 million at December 31, 2003 and $121 million at December 31, 2002. PG&E Corporation amortizes capitalized software costs ratably over the expected lives of the projects ranging from 3 to 15 years, commencing operational use, in accordance with regulatory requirements and recovery.

The carrying values of long-lived assets are evaluated in accordance with the provisions of SFAS No. 144. SFAS No. 144 became effective at the beginning of 2003 and supersedes SFAS No. 121, “Accounting for the Impairment or Disposal of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of,” and the accounting and reporting provisions of Accounting Principles Board Opinion No. 30, “Reporting the Results of Operations for a Disposal of a Segment of a Business.” The adoption of SFAS No. 144 did not have a material impact on the consolidated financial position, results of operations or cash flows of PG&E Corporation or the Utility. During 2002 and 2003, NEGT recorded certain impairment charges in accordance with SFAS No. 144 (see Note 5).

Gains and losses on debt extinguishments associated with regulated operations that are subject to the provisions of SFAS No. 71 are deferred and amortized over the remaining original amortization period of the debt reacquired, consistent with ratemaking principles. Gains and losses on debt extinguishments associated with unregulated operations are recognized at the time such debt is reacquired and are reported as interest expense.

The fair value of a financial instrument represents the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. Significant differences can occur between the fair value and carrying amount of financial instruments that are recorded at historical amounts.

PG&E Corporation and the Utility use the following methods and assumptions in estimating fair value disclosures for financial instruments:


	•	The fair values of cash and cash equivalents, restricted cash and deposits, net accounts receivable, short-term borrowings, accounts payable, customer deposits and the Utility’s variable rate pollution control loan agreements approximate their carrying values as of December 31, 2003 and 2002;

	•	The fair values of rate reduction bonds, PG&E Corporation’s 6 7/8% Senior Secured Notes, the Utility’s preferred stock and the Utility’s 7.90% deferrable interest subordinated debentures were determined based on quoted market prices; and

	•	The fair value of debt for which no market quotation is readily available, was determined with the assistance of third-party experts and using estimates of borrowing rates currently available to PG&E Corporation and the Utility for instruments of similar maturity. The fair value of a small portion of the Utility’s debt was determined using the present value of future cash flows. The fair value of PG&E Corporation’s 9.5% convertible subordinated debt was determined using the present value of future cash flows and the Black-Scholes option valuation model, including a stock volatility assumption of 35%.

The carrying amount and fair value of PG&E Corporation’s and the Utility’s financial instruments are as follows (the table below excludes financial instruments with fair values that approximate their carrying values, as these instruments are presented on the Consolidated Balance Sheets):

PG&E Corporation and the Utility account for the financial effects of regulation in accordance with SFAS No. 71. SFAS No. 71 applies to regulated entities whose rates are designed to recover the costs of providing service. SFAS No. 71 applies to all of the Utility’s operations except for its generation operations and a natural gas pipeline expansion project. The Utility is regulated by the CPUC, the FERC and the Nuclear Regulatory Commission, or NRC, among others.

SFAS No. 71 provides for the recording of regulatory assets and liabilities when certain conditions are met. Regulatory assets represent the capitalization of incurred costs that would otherwise be charged to expense when it is probable that the incurred costs will be included for ratemaking purposes in the future. Regulatory liabilities represent rate actions of a regulator that will result in amounts that are to be credited to customers through the ratemaking process.

To the extent that portions of the Utility’s operations cease to be subject to SFAS No. 71 or recovery is no longer probable as a result of changes in regulation or the Utility’s competitive position, the related regulatory assets and liabilities would be written off.

Regulatory assets are charged to expense during the period that the costs are reflected in regulated revenues.

The Utility’s regulatory asset related to rate reduction bonds is amortized simultaneously with the amortization of the rate reduction bonds liability, and is expected to be recovered by the end of 2007. The Utility’s regulatory assets related to deferred income tax will be recovered over the period of reversal of the accumulated deferred taxes to which they relate. Based on current regulatory ratemaking and income tax laws, the Utility expects to recover deferred income tax-related regulatory assets over periods ranging from 1 to 37 years. The Utility’s regulatory asset related to

the unamortized loss, net of gain, on reacquired debt will be recovered over the remaining original amortization period of the reacquired debt over periods ranging from 1 to 23 years. The Utility’s regulatory asset relating to post-transition period contract termination costs is being amortized and collected in rates on a straight-line basis until the end of September 2014, the contract’s original termination date. The Utility’s regulatory asset related to environmental compliance represents the portion of the Utility’s environmental liability recognized at the end of the period in excess of the amount that has been recovered through rates charged to customers. This amount will be recovered in future rates.

In general, the Utility does not earn a return on regulatory assets where the related costs do not accrue interest. Accordingly, the only regulatory asset on which the Utility earns a return on is the regulatory asset relating to unamortized loss, net of gain on reacquired debt.

The Utility’s regulatory liabilities related to costs of removal represent revenues collected for asset removal costs that the Utility expects to incur in the future. Historically, these removal costs have been recorded in accumulated depreciation; however, as a result of recent guidance from the staff of the SEC, the Utility reclassified this obligation to a regulatory liability during 2003. The regulatory liability associated with over-recovery of asset retirement costs represents timing differences between the recognition of nuclear decommissioning obligations in accordance with GAAP applicable to non-regulated entities, based on the adoption of SFAS No. 143 on January 1, 2003, and the amounts recognized for ratemaking purposes. The Utility’s regulatory liabilities related to employee benefit plan expenses represent the cumulative differences between expenses recognized for financial accounting purposes and expenses recognized for ratemaking purposes. These balances will be charged against expense to the extent that future financial accounting expenses exceed amounts recoverable for regulatory purposes. The Utility’s regulatory liability related to public purpose programs represents revenues designated for public purpose program costs that are expected to be incurred in the future. The Utility’s regulatory liability for rate reduction bonds represents the deferral of over-collected revenue associated with the rate reduction bonds that the Utility expects to return to ratepayers in the future.

The Utility’s regulatory liability related to surcharge revenues represents the estimated amount of previously collected surcharge revenues expected to be refunded to customers based upon current proceedings at the CPUC. In early January 2004, the CPUC issued a decision finding that the rate freeze mandated by AB 1890 ended on January 18, 2001. In mid-January 2004, the Utility entered into a rate design settlement agreement, or rate design settlement, with representatives of major customer groups that addresses revenue allocation and rate design issues associated with the decrease in the Utility’s revenue requirement resulting from the Settlement Agreement, DWR revenue requirements, and other CPUC actions. On February 11, 2004, a proposed decision was issued that would adopt the rate design settlement with a modification for DWR revenues. This proposed decision, if approved by the CPUC, combined with the January 2004 CPUC decision regarding the rate freeze, provides that the Utility will no longer collect the frozen rates and surcharges. Instead, it will collect the regulatory assets arising from the Settlement Agreement, as amortized into rates, and the revenue requirements established by the 2003 general rate case, or GRC, settlement discussed below as well as revenue requirements established in other proceedings. The CPUC’s proposed decision adopts the Utility’s request to revise electricity rates reflecting the terms of the rate design settlement based

on the Utility’s overall forecast revenue requirements for 2004. If ultimately approved, the Utility’s electricity customers would receive an electricity rate reduction of approximately 8.0%, on average, in March 2004, or shortly thereafter retroactive to January 1, 2004. The Utility expects that as a result of this rate reduction, electricity operating revenues would decrease by approximately $799 million compared to revenues generated at current rates. As a result of the anticipated rate decrease incorporating a refund of some surcharge revenues collected in 2003, the Utility has established a $125 million regulatory liability at December 31, 2003. In addition, if the 2003 GRC settlement is not approved, the net average reduction in electricity rates and associated reduction in electricity operating revenue will be even greater.

Sales balancing accounts accumulate differences between recorded revenues and revenues the Utility is authorized to collect through rates. Cost balancing accounts accumulate differences between recorded costs and costs the Utility is authorized to recover through rates. Under-collections that are probable of recovery are recorded as regulatory balancing account assets. Over-collections are recorded as regulatory balancing account liabilities. The Utility’s regulatory balancing accounts accumulate balances until they are refunded to or received from the Utility’s customers through authorized rate adjustments.

As a result of the California energy crisis discussed in Note 2, the Utility could no longer conclude that power generation and procurement-related balancing accounts met the requirements of SFAS No. 71. However, the Utility continues to record balancing accounts associated with its electricity transmission and distribution and natural gas transportation businesses.

In 2002 and 2003, the CPUC ordered the Utility to create certain electricity balancing accounts to track specific electric-related amounts, including shortfalls from baseline allowance increases and costs related to the self-generation incentive program, for which the CPUC has not yet determined the recovery method for these costs. In the decisions ordering the creation of these balancing accounts, the CPUC indicated that the recovery method of these amounts would be determined in the future. Because the Utility cannot conclude that the amounts in these balancing accounts are considered probable of recovery in future rates, the Utility has reserved these balances by recording a charge against earnings. As of December 31, 2003, the reserve for these balances was approximately $200 million.

The Utility’s current regulatory balancing account assets comprise the following:

The Utility’s current regulatory balancing account liabilities comprise the following:

The Utility expects to collect from or refund to its customers the balances included in current balancing accounts receivable and payable within the next twelve months. Regulatory balancing accounts that the Utility does not expect to collect or refund in the next twelve months are included in non-current regulatory assets and liabilities.

Electricity revenues, which are comprised of generation, transmission, and distribution services, were billed to the Utility’s customers at the CPUC-approved “bundled” electricity rate. Natural gas revenues, which are comprised of transmission and distribution services, are also billed at CPUC-approved rates. The Utility’s revenues are recognized as natural gas and electricity are delivered, and include amounts for services rendered but not yet billed at the end of each year.

As further discussed in Note 12, in January 2001, the California Department of Water Resources, or DWR, began purchasing electricity to meet the portion of demand of the California investor-owned electric utilities that was not being satisfied from their own generation facilities and existing electricity contracts. Under California law, the DWR is deemed to sell the electricity directly to the Utility’s retail customers, not to the Utility. Therefore, the Utility acts as a pass-through entity for electricity purchased by the DWR on behalf of its customers. Although charges for electricity provided by the DWR are included in the amounts the Utility bills its customers, the Utility deducts from its electricity revenues the amounts passed through to the DWR. The pass-through amounts are based on the quantities of electricity provided by the DWR that are consumed by customers at the CPUC-approved remittance rate. These pass-through amounts are excluded from the Utility’s electricity revenues in its Consolidated Statements of Operations.

PG&E Corporation, through the Utility, engages in price risk management activities for non-trading purposes. Non-trading derivative instruments designated as cash flow hedges are entered into to hedge variable price risk associated with the purchase and sale of commodities and to hedge variable interest rates on long-term debt. Price risk management activities include the continuation of power forward contracts that were in existence before the Utility’s Chapter 11 proceeding, new power contracts entered into since January 1, 2003 when the Utility resumed procurement of electricity, contracts related to the natural gas portfolio and interest rate hedges related to the issuance of debt under the Utility’s Plan of Reorganization.

Derivative instruments associated with non-trading activities include forward contracts, futures, swaps, options and other contracts. They are accounted for at fair value unless they qualify for the normal purchases and sales exemption as further discussed below.

Derivative instruments that are recorded on PG&E Corporation’s and the Utility’s Consolidated Balance Sheets are presented in other current assets. For derivative instruments designated as cash flow hedges associated with non-regulated operations, unrealized gains or losses related to the effective portion of the change in the fair value of the derivative instrument is recorded in accumulated other comprehensive income until the hedged item is recognized in earnings. The ineffective portion of the change in the fair value of the derivative instrument is recognized immediately in earnings. For derivative instruments designated as cash flow hedges associated with the Utility’s regulated operations, unrealized gains and losses related to the effective and ineffective portions of the change in the fair value of the derivative instrument are deferred and recorded in regulatory liabilities and regulatory assets to the extent they are recoverable in future rates.

PG&E Corporation and the Utility discontinue hedge accounting prospectively if they determine that the derivative instrument no longer qualifies as an effective hedge, or when the forecasted transaction is no longer probable of occurring. If hedge accounting is discontinued because the derivative instrument no longer qualifies as an effective hedge, then the derivative instrument continues to be reflected at fair value, with any subsequent changes in fair value recognized immediately in earnings. Gains and losses related to a derivative instrument for which hedge accounting has been discontinued that were previously recorded in accumulated other comprehensive income will remain in accumulated other comprehensive income until the hedged item is recognized in earnings, unless the forecasted transaction is no longer probable of occurring. If hedge accounting is discontinued because the forecasted transaction is no longer probable of occurring, then the gains and losses from the derivative instrument that were previously recorded in accumulated other comprehensive income will be immediately recognized in earnings. When the hedged item matures or is sold, the gains and losses deferred in accumulated other comprehensive income are recognized in earnings.

Net realized and unrealized gains or losses on non-trading derivative instruments are included in various lines on PG&E Corporation’s and the Utility’s Consolidated Statements of Operations, including cost of electricity, cost of natural gas and interest expense. Cash inflows and outflows associated with the settlement of price risk management activities are recognized in operating cash flows on PG&E Corporation’s and the Utility’s Consolidated Statements of Cash Flows.

Non-trading derivative instruments that are not designated as hedges or that are not eligible for the normal purchases and sales exception are adjusted to fair value through income.

The Utility estimates the fair value of its contracts using the mid-point of quoted bid and ask forward prices, including quotes from counterparties, brokers, electronic exchanges and published indices, supplemented by online price information from news services. When market data is not available, the Utility uses models to estimate fair value.

PG&E Corporation and the Utility have derivative commodity instruments for the physical delivery of purchase and sale quantities transacted in the normal course of business. These derivative instruments are exempt from the requirements of SFAS No. 133 under the normal purchase and sales exception, and are not reflected on the balance sheet at fair value. Derivative instruments treated as normal purchases or sales are recorded and recognized in income using accrual accounting. Therefore, revenues are recognized as earned and expenses are recognized as incurred.

The Utility has commodity contracts that are not derivative instruments. Revenues are recorded as earned and expenses are recognized as incurred.

PG&E Corporation and the Utility account for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” as allowed by SFAS No. 123, “Accounting for Stock-Based Compensation,” or SFAS No. 123, as amended by SFAS No. 148, “Accounting for Stock-Based Compensation-Transition and Disclosures, an Amendment of FASB Statement No. 123,” or SFAS No. 148. Under the intrinsic value method, PG&E Corporation and the Utility do not recognize any compensation expense for stock options as the exercise price is equal to the fair market value of a share of PG&E Corporation common stock at the time the options are granted. If compensation expense had been recognized using the fair value-based method under SFAS No. 123 and using valuation assumptions disclosed in Note 10, then PG&E Corporation’s pro forma consolidated earnings (loss) and earnings (loss) per share would have been as follows:

Had compensation expense been recognized using the fair value-based method under SFAS No. 123, the Utility’s pro forma consolidated earnings would have been as follows:

Accumulated other comprehensive income (loss) reports a measure for accumulated changes in equity of an enterprise that results from transactions and other economic events other than transactions with shareholders. The following table sets forth the changes in each component of accumulated other comprehensive income (loss):

Amounts included in accumulated other comprehensive income (loss) related to discontinued operations were $(77) million at December 31, 2003, and $(93) million at December 31, 2002.

On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California. The Utility has retained control of its assets and is authorized to operate its business as a debtor-in-possession during its Chapter 11

proceeding. PG&E Corporation and subsidiaries of the Utility, including PG&E Funding, LLC (which issued rate reduction bonds) and PG&E Holdings, LLC (which holds stock of the Utility), are not included in the Utility’s Chapter 11 proceeding.

Claims filed in the Chapter 11 proceeding totaled approximately $51.5 billion. Of these claims, approximately $9.8 billion related to ISO, Power Exchange, or PX, and generator claims. Under a bankruptcy court order the aggregate allowable amount of ISO, PX and generator claims is limited to approximately $1.6 billion after giving effect to approximately $200 million in pre-petition offset. The Utility expects that this approximately $1.6 billion amount will be further reduced as a result of certain proceedings pending at the FERC. Of the approximately $43.3 billion of filed claims that remained, approximately $23.8 billion has been disallowed by the bankruptcy court due to objections, claim withdrawals and agreements with claimants. The Utility has objected to, or intends to object to, approximately $900 million of the remaining approximately $19.5 billion of filed claims. In addition, of the remaining approximately $19.5 billion of filed claims, approximately $5.5 billion are expected to pass through the Chapter 11 proceeding and be satisfied in the ordinary course of business. Since the Utility’s filing under Chapter 11 in April 2001, the Utility has made approximately $2.0 billion in claims-related principal payments.

The Utility has recorded its estimate of all valid claims at December 31, 2003 as approximately $9.5 billion of liabilities subject to compromise, including interest on disputed claims and approximately $2.7 billion of long-term debt. At December 31, 2002, the Utility had recorded approximately $9.4 billion of liabilities subject to compromise. The increase from $9.4 billion is mainly due to interest accruals during the twelve months ended December 31, 2003.

The bankruptcy court has authorized certain payments and actions necessary for the Utility to continue its normal business operations while operating as a debtor-in-possession. For example, the Utility is authorized to pay employee wages and benefits, amounts due under contracts with the majority of qualifying facilities, environmental remediation expenses and expenditures related to property, plant and equipment. In addition, the Utility is authorized to refund certain customer deposits, use certain bank accounts and make cash collateral deposits and assume responsibility for various hydroelectric contracts. The Utility also has received permission from the bankruptcy court to make payments on pre- and post-petition interest on certain claims, pre-petition secured debt that has matured and certain other claims.

The Utility has agreed to pay pre- and post-petition interest on liabilities subject to compromise at the rates set forth below.

Since the Utility did not emerge from Chapter 11 on or before September 15, 2003, the interest rates for commercial paper claims, floating rate notes, senior notes, medium-term notes and revolving line of credit claims increased 0.75% over the originally agreed upon rates for periods on and after September 15, 2003. The interest rates for these claims will increase by an additional 0.375% if the effective date of a plan of reorganization does not occur on or before March 15, 2004. For other claims, the Utility has recorded interest at the contractual or FERC-tariffed interest rate. When those rates do not apply, the Utility has recorded interest at the federal judgment rate.

In September 2001, PG&E Corporation and the Utility proposed a plan of reorganization that would have disaggregated the Utility’s businesses. In April 2002, the CPUC, later joined by the Official Committee of Unsecured Creditors, proposed an alternate plan of reorganization that would not have disaggregated the Utility’s businesses. On December 19, 2003, the CPUC, PG&E Corporation and the Utility entered into a settlement agreement, or the Settlement Agreement, that contemplated a new plan of reorganization to supersede the competing plans. Under the Settlement Agreement, the Utility remains vertically integrated. On December 22, 2003, the bankruptcy court confirmed the new plan of reorganization, or the Plan of Reorganization, which fully incorporates the Settlement Agreement. The Utility expects to pay all allowed creditor claims (except for the claims of holders of pollution control-related bond obligations that will be reinstated) from the proceeds of a public offering of long-term debt, cash on hand, and draws on credit facilities. The Utility also will establish one or more escrow accounts for disputed claims and deposit cash in these accounts. Under the Plan of Reorganization, allowed environmental, fire suppression, pending litigation and tort claims, and workers’ compensation claims will be satisfied by the Utility in the ordinary course of business.

On January 20, 2004, several parties filed applications with the CPUC requesting that the CPUC rehear and reconsider its decision approving the Settlement Agreement on the basis that the Settlement Agreement does not comply with California law. Although the CPUC is not required to act on these applications within a specific time period, if the CPUC has not acted on an application within 60 days, that application may be deemed denied for purposes of seeking judicial review. In addition, the two CPUC commissioners who did not vote to approve the Settlement Agreement and a municipality have filed appeals of the bankruptcy court’s confirmation order in the U.S. District Court for the Northern District of California, or the District Court, citing similar objections to those included in the request for rehearing and reconsideration of the CPUC’s decision. On January 5, 2004, the bankruptcy court denied a request to stay the implementation of the Plan of Reorganization until the appeals are resolved. The District Court will set a schedule for briefing and argument of the appeals at a later date. No additional parties may request rehearings or make appeals of the CPUC’s approval of the Settlement Agreement or the bankruptcy court’s confirmation order. PG&E Corporation and the Utility cannot predict the timing and outcome of the requests for rehearing and appeals.

The Plan of Reorganization provides that it will not become effective unless and until each of the following conditions is satisfied or waived:


	•	The effective date occurs on or before March 31, 2004;

	•	All actions, documents and agreements necessary to implement the Plan of Reorganization are effected or executed;

	•	The Utility and PG&E Corporation have received all authorizations, consents, regulatory approvals, rulings, letters, no-action letters, opinions or documents that the Utility and PG&E Corporation determine are necessary to implement the Plan of Reorganization;

	•	The Plan of Reorganization has not been modified in a material way since the date of confirmation;

	•	The Utility has consummated the sale of the debt securities provided for under the Plan of Reorganization;

	•	Moody’s Investors Service, or Moody’s, has issued an issuer rating for the Utility of not less than Baa3 and Standard & Poor’s, or S&P, has issued long-term issuer credit ratings for the Utility of not less than BBB-;

	•	Moody’s has issued a credit rating of not less than Baa3 for the debt securities provided for under the Plan of Reorganization and S&P has issued a credit rating of not less than BBB- for the debt securities provided for under the Plan of Reorganization;

	•	The CPUC has given final approval of the Settlement Agreement;

	•	The Utility, PG&E Corporation and the CPUC have executed and delivered the Settlement Agreement;

	•	The CPUC has given final approval for all of the financings, securities and accounts receivable programs provided for in the Plan of Reorganization; and


	•	The CPUC has given final approval for all rates, tariffs and agreements necessary to implement the Plan of Reorganization.

As described above, the Plan of Reorganization provides that it will not become effective unless and until the CPUC has given final approval of the Settlement Agreement, the financings, securities and accounts receivable programs provided for in the Plan of Reorganization and all rates, tariffs and agreements necessary to implement the Plan of Reorganization. For purposes of these conditions, final approval means approval on behalf of the CPUC that is not subject to any pending appeal or further right of appeal, or approval on behalf of the CPUC that, although subject to a pending appeal or further right of appeal, has been agreed by the Utility and PG&E Corporation to constitute final approval. Thus, the terms of the Plan of Reorganization permit the Utility and PG&E Corporation to cause the Plan of Reorganization to become effective (and permit the Utility to issue the debt securities provided for under the Plan of Reorganization) while the CPUC’s approvals are subject to pending appeals or further rights of appeal. In addition, the Plan of Reorganization provides that the Utility may waive the conditions described under the first five bullets listed above.

The Settlement Agreement contains a statement of intent that it is in the public interest to restore the Utility to financial health and maintain and improve the Utility’s financial condition in the future to ensure that the Utility is able to provide safe and reliable electricity and natural gas to its customers at just and reasonable rates. In addition, the Settlement Agreement includes a statement of intent that it is fair and in the public interest to allow the Utility to recover prior uncollected costs over a reasonable time and to provide for the Utility’s shareholders to earn a reasonable rate of return on the Utility’s business.


	•	The Settlement Agreement establishes a $2.21 billion, after-tax, regulatory asset (which is equivalent to an approximately $3.7 billion, pre-tax, regulatory asset), or the Regulatory Asset, as a new, separate and additional part of the Utility’s rate base that will be amortized on a “mortgage-style” basis over nine years beginning January 1, 2004. Under this amortization methodology, annual after-tax collections of a $2.21 billion regulatory asset are estimated to range from approximately $140 million in 2004 to approximately $380 million in 2012, although these amounts will be reduced as discussed below. The Regulatory Asset will be recognized when it meets the SFAS No. 71 accounting criteria for probability of recovery in rates. Upon recognition of the Regulatory Asset the Utility will reflect a one-time non-cash gain equal to the Regulatory Asset. The Regulatory Asset will be fully amortized by the end of 2012.

	•	The unamortized balance of the Regulatory Asset will earn a rate of return on its equity component of no less than 11.22% annually for its nine-year term and, after the equity component of the Utility’s capital structure reaches 52%, the authorized equity component of this regulatory asset will be no less than 52% for the remaining term. The rate of return on the Regulatory Asset will be reduced if the Utility completes the refinancing discussed below. The equity and debt components of the Utility’s rate of return will be eliminated. Instead the Utility would collect from customers amounts sufficient to service the securitized debt.

	•	The net after-tax amount of any refunds, claim offsets or other credits the Utility receives from energy suppliers relating to specified procurement costs incurred during the California energy crisis and arising from the settlement of CPUC litigation against El Paso Natural Gas Company, or El Paso, related to any electricity (but not natural gas) refunds will reduce the outstanding balance of the Regulatory Asset. On January 26, 2004 in a filing with the CPUC, the Utility proposed to reduce the Regulatory Asset by approximately $189 million, after-tax, for these matters.


	•	The CPUC deemed the Utility’s adopted 2003 electricity generation rate base of approximately $1.6 billion just and reasonable and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation would allow for the recognition of an additional after-tax regulatory asset of approximately


		$800 million (which is equivalent to an approximately $1.3 billion pre-tax regulatory asset). This regulatory asset and an equivalent one-time non-cash gain will be recorded when it meets the probability requirements of SFAS No. 71. The individual components of the regulatory assets will be amortized over their respective lives, with a weighted average life of approximately 16 years.

	•	The CPUC will timely act upon the Utility’s applications to collect in rates prudently incurred costs of (including return of and return on) any new and reasonable investment in utility plant and assets and will timely adjust the Utility’s rates to ensure that the Utility collects in its rates fixed amounts to service existing rate reduction bonds, Regulatory Asset amortization and return, and base revenue requirements. The Settlement Agreement provides that the CPUC will not discriminate against the Utility because of the Utility’s Chapter 11 proceeding and the Utility’s previous actions concerning the energy crisis.

	•	The CPUC will set the Utility’s capital structure and authorized return on equity in its annual cost of capital proceedings in its usual manner. However, from January 1, 2004 until Moody’s has issued an issuer rating for the Utility of not less than A3 or S&P has issued a long-term issuer credit rating for the Utility of not less than A-, the Utility’s authorized return on equity will be no less than 11.22% per year and its authorized equity ratio for ratemaking purposes will be no less than 52%. However, for 2004 and 2005, the Utility’s authorized equity ratio will be the greater of the proportion of equity approved in the Utility’s 2004 and 2005 cost of capital proceedings, or 48.6%.

	•	The Utility’s retail electricity rates were maintained at current levels through December 31, 2003. The Settlement Agreement includes a statement of intent that as a result of the Settlement Agreement and the Plan of Reorganization, retail electricity rates may be reduced in January 2004 with future reductions expected thereafter.

	•	The CPUC also agreed to act promptly on certain of the Utility’s pending ratemaking proceedings, including the Utility’s pending 2003 general rate case, or GRC. The outcome of these proceedings may result in the establishment of additional regulatory assets on the Utility’s Consolidated Balance Sheets.

Under the Settlement Agreement, PG&E Corporation and the Utility agreed to seek to refinance the remaining unamortized pre-tax balance of the Regulatory Asset and related federal, state and franchise taxes, up to a total of $3.0 billion, as expeditiously as practicable after the effective date of the Plan of Reorganization using a securitized financing supported by a dedicated rate component, provided the following conditions are met:


	•	Authorizing California legislation satisfactory to the CPUC, The Utility Reform Network, or TURN, and the Utility is passed and signed into law allowing securitization of the Regulatory Asset and associated federal and state income and franchise taxes and providing for the collection in the Utility’s rates of any portion of the associated tax amounts not securitized;

	•	The CPUC determines that, on a net present value basis, the refinancing would save customers money over the term of the securitized debt compared to the Regulatory Asset;

	•	The refinancing 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, or IRS, confirming that neither the refinancing nor the issuance of the securitized debt is a presently taxable event.

The Utility would be permitted to complete the refinancing in up to two tranches up to one year apart, and would issue sufficient callable debt or debt with earlier maturities as part of the Plan of Reorganization to accommodate the refinancing supported by a dedicated rate component. Upon refinancing with securitization, the equity and debt components of the Utility’s rate of return on the Regulatory Asset would be eliminated. Instead the Utility would collect from customers amounts sufficient to service the securitized debt. The Utility would use the securitization proceeds to rebalance its capital structure in order to maintain the capital structure provided for under the Settlement Agreement.

The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts, unless each of the following conditions has been met:


	•	After assumption, the Utility’s issuer credit rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating from S&P will be no less than A;

	•	The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

	•	The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

Under the Settlement Agreement, the CPUC retains and, after any assumption of the DWR contracts, will retain the right to review the prudence of the Utility’s administration and dispatch of the DWR contracts consistent with applicable law.

The CPUC agreed and acknowledged that the headroom, surcharge and base revenues accrued or collected by the Utility through and including December 31, 2003 are the property of the Utility’s Chapter 11 estate, have been or will be used for utility purposes, including to pay creditors in the Utility’s Chapter 11 proceeding, and have been included in the Utility’s retail electricity rates consistent with state and federal law. The Settlement Agreement defines headroom as the Utility’s total net after-tax income reported under GAAP, less earnings from operations (a non-GAAP financial measure that has been historically reported by PG&E Corporation in its earnings press release), plus after-tax amounts accrued for Chapter 11-related administration and Chapter 11-related interest costs, all multiplied by 1.67, provided that the calculation reflects the outcome of the Utility’s 2003 GRC. The Settlement Agreement provides that if headroom revenue accrued by the Utility during 2003 is greater than $875 million, pre-tax, the Utility will refund the excess to ratepayers.


	•	On or as soon as practicable after the later of the effective date of the Plan of Reorganization, or the date the CPUC decision approving the Settlement Agreement is no longer subject to appeal, the Utility will dismiss with prejudice its case against the CPUC Commissioners related to the federal filed rate doctrine, withdraw the original plan of reorganization and dismiss certain other pending proceedings. In exchange, the CPUC has established and authorized the collection of the Regulatory Asset and the Utility’s rate base for its electricity generation, and, on or as soon as practicable after the effective date, the CPUC will resolve phase 2 of the pending Annual Transition Cost Proceeding, in which the CPUC is reviewing the reasonableness of the Utility’s procurement costs incurred during the energy crisis, with no adverse impact on the Utility’s requested cost recovery.

	•	On or as soon as practicable after the later of the effective date of the Plan of Reorganization or the date the CPUC decision approving the Settlement Agreement is no longer subject to appeal, PG&E Corporation, the Utility, and the CPUC will execute mutual releases and dismissals with prejudice of specified claims, actions, or regulatory proceedings arising out of or related in any way to the energy crisis or the implementation of Assembly Bill, or AB, 1890, including the CPUC’s investigation into past holding company actions during the California energy crisis (but only as to past actions, not prospective matters).

Withdrawal of Applications in Connection with the Original Plan of Reorganization

As required by the Settlement Agreement, the Utility has requested a stay of all proceedings before the FERC, the NRC, the SEC and other regulatory agencies relating to approvals sought to implement the original plan of reorganization. The Utility also has suspended all actions to obtain or transfer licenses, permits and franchises to implement the original plan of reorganization. On the effective date of the Plan of Reorganization, or as soon thereafter as practicable, the Utility and PG&E Corporation will withdraw or abandon all applications for these

regulatory approvals. In addition, the Utility and PG&E Corporation have agreed that for the term of the Regulatory Asset, neither the Utility nor PG&E Corporation, nor their respective affiliates, will make any filings under Sections 4, 5 or 7 of the Natural Gas Act to transfer ownership or ratemaking jurisdiction over the Utility’s intrastate gas pipeline and storage facilities, which means that these facilities will remain primarily subject to CPUC regulation. The Utility and PG&E Corporation have also agreed that the CPUC has jurisdiction to review and approve any proposal to dispose of the Utility’s property necessary or useful in the performance of the Utility’s duties to the public.


	•	The Utility will encumber with conservation easements or donate approximately 140,000 acres of land to public agencies or non-profit conservation organizations;

	•	The Utility will establish a California non-profit corporation to oversee the environmental enhancements associated with these lands and fund it with $100 million in cash over ten years, although the Utility will be entitled to recover these payments in rates; and

	•	The Utility will create a non-profit corporation funded with $30 million payable by the Utility over five years, with no recovery of these payments in rates, dedicated to support research and investment in clean energy technology, primarily in the Utility’s service territory.

Of the approximately 140,000 acres referred to above, approximately 44,000 acres may be either donated or encumbered with conservation easements. The remaining land contains the Utility’s or a joint licensee’s hydroelectric generation facilities and may only be encumbered with conservation easements.

The Settlement Agreement generally terminates nine years after the effective date of the Plan of Reorganization, except that the rights of the parties to the Settlement Agreement that vest on or before termination, including any rights arising from any default under the Settlement Agreement, will survive termination for the purpose of enforcement. The parties agreed that the bankruptcy court would have jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement, the Plan of Reorganization and the confirmation order. The parties also agreed that the Settlement Agreement, the Plan of Reorganization or any order entered by the bankruptcy court contemplated or required to implement the Settlement Agreement or the Plan of Reorganization will be irrevocable and binding on the parties and enforceable under federal law, notwithstanding any future decisions or orders of the CPUC.

The Settlement Agreement requires the Utility to reimburse the CPUC for its professional fees and expenses incurred in connection with the Chapter 11 proceeding once the Plan of Reorganization is confirmed. These amounts will be recovered from customers over a reasonable time of up to four years. This accrual will be recorded when the applicable GAAP requirements are met. PG&E Corporation’s professional fees and expenses incurred in connection with the Chapter 11 proceeding will not be reimbursed by the Utility or from the Utility’s customers.

The following table summarizes PG&E Corporation’s and the Utility’s long-term debt that matures in one year or more from the date of issuance:

On July 2, 2003, PG&E Corporation completed a private placement of $600 million of 6 7/8% Senior Secured Notes due July 15, 2008, or Senior Secured Notes. The net proceeds of the offering, approximately $581 million, together with cash on hand, were used to repay the principal outstanding under PG&E Corporation’s October 2002 credit agreement of approximately $720 million, $15 million of in-kind interest and a $52 million prepayment premium. The payment resulted in the termination of PG&E Corporation’s existing credit agreement and the release of liens on PG&E Corporation’s shares of NEGT, as well as the prior lien on approximately 94% of the outstanding common stock of the Utility.

Interest is payable semi-annually in arrears on January 15 and July 15, commencing on January 15, 2004. The Senior Secured Notes are secured by a perfected first-priority security interest in approximately 94% of the outstanding common stock of the Utility that is owned by PG&E Corporation. With respect to 35% of such common stock pledged for the benefit of the lenders, the holders of the Senior Secured Notes have customary rights of a pledge of common stock, provided that certain regulatory approvals may be required in connection with any foreclosure on and

any exercise of the right to vote such stock. With respect to the remaining 65%, such common stock has been pledged for the benefit of the holders, but the holders have no ability to control such common stock under any circumstances and do not have any of the typical rights and remedies of a secured creditor. However, the holders do have the right to receive any cash distributions associated with such common stock.

The Senior Secured Notes are effectively subordinated to all indebtedness and other obligations (including trade payables) of PG&E Corporation’s subsidiaries. In the event of a bankruptcy, liquidation or reorganization of any of PG&E Corporation’s subsidiaries, such subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to PG&E Corporation.

PG&E Corporation may redeem all or a portion of the Senior Secured Notes at the following redemption premiums, plus accrued and unpaid interest.

The indenture, among other restrictions, also prohibits PG&E Corporation from declaring or paying dividends unless it meets certain financial criteria or achieves an investment grade credit rating. Regardless of these restrictions, PG&E Corporation may pay a dividend from the proceeds of cash distributions from the Utility.

PG&E Corporation has agreed to have the Senior Secured Notes registered by June 26, 2004. If the Senior Secured Notes have not been registered by the specified date, the annual interest rate will increase by approximately 1% until they have been registered.

On June 25, 2002, PG&E Corporation issued 7.50% Convertible Subordinated Notes, or Convertible Notes, due 2007 in the aggregate principal amount of $280 million. The Convertible Notes may be converted by the holders into 18,558,655 shares of the common stock of PG&E Corporation.

Concurrent with the October 18, 2002 financing of the $720 million credit agreement due in 2006, now paid in full, the indenture relating to the Convertible Notes was amended as follows:


	•	The cross default provisions related to NEGT and its subsidiaries was deleted;

	•	The interest rate on the Convertible Notes increased to 9.50% from 7.50%;

	•	The maturity of the Convertible Notes was extended from June 30, 2007 to June 30, 2010; and

	•	PG&E Corporation provided the holders of the Convertible Notes with a one-time right to require PG&E Corporation to repurchase the Convertible Notes on June 30, 2007 plus accrued and unpaid interest.

The holders of the Convertible Notes are also entitled to receive dividend payments as if they hold the common shares subject to the conversion feature.

Concurrent with the negotiation of new terms and amendment to the previously existing credit agreement in June 2002, now paid in full, warrants to purchase 2,397,541 shares of PG&E Corporation’s common stock were issued, at an exercise price of $0.01 per share. In October 2002, the above mentioned credit agreement was amended to increase the size of the facility by $300 million to a total of $720 million. In connection with this amendment, PG&E Corporation issued to affiliates of the lenders additional warrants to purchase 2,669,390 shares of PG&E Corporation’s common stock, with an exercise price of $0.01 per share. At December 31, 2003, there were 4,353,113 of these warrants outstanding, of which 7,415 were subsequently exercised in January 2004.

The following information about the Utility’s debt reflects the terms of the debt as of December 31, 2003. As discussed in Note 2 “The Plan of Reorganization,” substantially all of this debt will be refinanced with the proceeds of a public offering of long-term debt, cash on hand and draws on credit facilities.

The Utility issued first and refunding mortgage bonds, or Mortgage Bonds, in various series that bear annual interest rates ranging from 5.85% to 8.80%. All real property and substantially all personal property of the Utility are subject to the lien of the mortgage, and the Utility is required to make semi-annual sinking fund payments for the retirement of the Mortgage Bonds. While in Chapter 11, the Utility is prohibited from making payments on the Mortgage Bonds without permission from the bankruptcy court. The bankruptcy court approved the payment of $333 million of mortgage bonds that matured in March 2002 and $281 million in August 2003, and has also approved the payment of interest in accordance with the terms of the Mortgage Bonds. In January 2004, the Utility filed a motion requesting that the bankruptcy court approve the payment of $310 million of Mortgage Bonds maturing in March 2004.

Mortgage Bonds outstanding at December 31, 2003 and 2002 include $345 million of bonds held in trust for the California Pollution Control Financing Authority, or CPCFA, with interest rates ranging from 5.85% to 6.63% and maturity dates ranging from 2009 to 2023.

In November 2000, the Utility issued $680 million of five-year senior notes, or Senior Notes, bearing an interest rate of 7.38%. The Utility used the net proceeds to repay short-term borrowings incurred to finance power purchases and for other general corporate purposes. These Senior Notes contain interest rate adjustments dependent upon the Utility’s unsecured debt ratings.

As a result of the Utility’s credit rating downgrades in January 2001, the interest rate on the Senior Notes was increased by 1.75%. In addition, in April 2001, an interest premium penalty of 0.5% was imposed due to the Utility’s failure to make a public offering. As a result, the bankruptcy court approved a motion by various unsecured creditors increasing the interest rate on the Senior Notes to 9.63% effective November 1, 2000. The interest rate on the Senior Notes was increased by an additional 0.375% on February 15, 2003 and September 15, 2003 because a Utility plan of reorganization did not become effective on or before those dates. If the effective date of a plan of reorganization does not occur on or before March 15, 2004, the interest rate will increase by an additional 0.375%. In 2001, the Utility’s Chapter 11 filing and failure to make payments on the Senior Notes were events of default. In 2002, the bankruptcy court authorized the Utility to make quarterly interest payments on these loans. The Senior Notes are classified as liabilities subject to compromise in the Consolidated Balance Sheets at December 31, 2003 and 2002.

Pollution control loan agreements, or Loans, held in trust for the CPCFA totaled $814 million at December 31, 2003 and 2002. Interest rates on $614 million of the Loans are variable. For 2003, the variable interest rates ranged from 0.75% to 1.31%. These Loans are subject to redemption by the holder under certain circumstances. They were secured primarily by irrevocable letters of credit from certain banks, which based on terms negotiated in 2002 and 2003, mature in 2004 through 2005. On March 1, 2001, $200 million of the Loans were converted to a fixed rate obligation with an interest rate of 5.35% with credit supported by bond insurance. In 2002, the bankruptcy court authorized the Utility to make quarterly interest payments on the variable interest rate Loans and semiannual interest payments on the fixed interest rate Loans.

In April and May 2001, $454 million of the Loans were accelerated and the banks paid the amounts due under the letters of credit, resulting in a reimbursement obligation from the Utility to the banks. The Utility had been unable to make principal or interest payments to the banks due to its Chapter 11 filing, an event of default, and accordingly amounts outstanding at December 31, 2003 and 2002, under the related loans are classified as liabilities subject to compromise in the Consolidated Balance Sheets at December 31, 2003 and 2002. In 2002, the bankruptcy court order authorized the Utility to make quarterly interest payments on these loans.

On the effective date of the Plan of Reorganization, the Utility may reinstate $814 million of the Loans.

The Utility has $287 million of outstanding unsecured medium-term notes, or Medium-Term Notes, due from 2004 to 2014 with interest rates ranging from 6.56% to 9.20% at December 31, 2003. The Medium-Term Notes are also in default as the Utility has been unable to make interest and principal repayments on maturity due to its Chapter 11 proceeding. The interest rate on the Medium-Term Notes increased by an additional 0.375% on February 15, 2003 and September 15, 2003 because a plan of reorganization did not become effective on or before

those dates. The outstanding principal amounts of the Medium-Term Notes at December 31, 2003 and 2002 are classified as liabilities subject to compromise in the accompanying financial statements. In 2002, the bankruptcy court authorized the Utility to make quarterly interest payments on the Medium-Term Notes.

On November 28, 1995, PG&E Capital I, or Capital I, a wholly owned subsidiary of the Utility, issued 12 million shares of 7.90% Cumulative Quarterly Income Preferred Securities, or QUIPS, with a total liquidation value of $300 million. Concurrent with the issuance of the QUIPS, Capital I issued to the Utility 371,135 shares of common stock securities with a total liquidation value of $9 million. Capital I in turn used the net proceeds from the QUIPS offering and issuance of the common stock securities to purchase 7.90% Deferrable Interest Subordinated Debentures, or QUIDS, due 2025 issued by the Utility with a value of $309 million at maturity.

The Utility’s Chapter 11 filing on April 6, 2001, was an event of default under the trust agreement. On March 27, 2002, the bankruptcy court issued an order authorizing the Utility to pay pre- and post-petition interest to holders of certain undisputed claims, including the QUIDS, and on May 6, 2002, the Utility made payments representing interest accrued through February 28, 2002, which was then passed through by the trust to the holders of the QUIPS. Capital I was liquidated by the trustee under the terms of the trust agreement on May 24, 2002. Upon liquidation of Capital I, the holders of the QUIPS received a like amount of QUIDS after satisfaction of Capital I’s liabilities to creditors. The terms and interest payments on the QUIDS correspond to the terms and dividend payments of the QUIPS.

The Utility has continued to make scheduled quarterly interest payments. The QUIDS are included in financing debt classified as liabilities subject to compromise on PG&E Corporation’s and the Utility’s Consolidated Balance Sheets at December 31, 2003 and 2002.

At December 31, 2003, PG&E Corporation’s and the Utility’s combined aggregate amounts of maturing long-term debt as scheduled are reflected in the table below:


⁽¹⁾	Table is based upon contractual maturity dates

⁽²⁾	The expected maturity dates for pollution control loan agreements with variable interest rates are based on the maturity dates of the letters of credit securing the loans.

The following table summarizes the Utility’s lines of credit. PG&E Corporation does not maintain credit facilities or short-term borrowings.

At December 31, 2003 and 2002, the Utility had $938 million outstanding on a defaulted $1 billion five-year revolving credit facility. The bank terminated its outstanding commitment with the default. The interest rate on the revolving credit facility increased by an additional 0.375% on February 15, 2003 and September 15, 2003 because a plan of reorganization did not become effective on or before those dates. The weighted average interest rate was 8.75% at December 31, 2003 and 8.00% at December 31, 2002. This facility was used to support the Utility’s commercial paper program and other liquidity requirements. The outstanding balance is classified as liabilities subject to compromise on the December 31, 2003 and 2002 Consolidated Balance Sheets. In 2002, the bankruptcy court authorized the Utility to make quarterly interest payments on these loans.

Bank Borrowing — Letters of Credit for Accelerated Pollution Control Bonds

As previously discussed, in April and May 2001 four pollution control loan agreements totaling $454 million were accelerated by the note holders. These accelerations were funded by various banks under letter of credit agreements resulting in similar obligations from the Utility to the banks. The weighted average interest rate was 5.50% at December 31, 2003 and 5.75% at December 31, 2002.

The Utility issued a total of $1.24 billion of 364-day floating rate notes in November 2000, with interest payable quarterly. The interest rate on the floating notes increased by an additional 0.375% on February 15, 2003 and September 15, 2003 because a plan of reorganization did not become effective on or before those dates. The weighted average interest rate was 8.33% at December 31, 2003 and 7.58% at December 31, 2002. These notes were not paid on the maturity date of October 31, 2001, resulting in an event of default. In 2002, an order by the bankruptcy court authorized the Utility to make quarterly interest payments on these loans.

The total amount of commercial paper outstanding at December 31, 2003 and 2002 was $873 million. The Utility has been in default on its commercial paper obligations since January 17, 2001. The interest rate on the commercial paper increased by an additional 0.375% on February 15, 2003 and September 15, 2003, because a Utility plan of reorganization did not become effective on or before those dates. The weighted average interest rate on the Utility’s commercial paper obligation was 8.22% at December 31, 2003 and was 7.47% at December 31, 2002. In 2002, an order by the bankruptcy court authorized the Utility to make quarterly interest payments on these loans.

In December 1997, PG&E Funding, LLC, a limited liability corporation wholly owned by and consolidated by the Utility, issued $2.9 billion of rate reduction bonds. The proceeds of the rate reduction bonds were used by PG&E Funding, LLC to purchase from the Utility the right, known as “transition property,” to be paid a specified amount from a non-bypassable charge levied on residential and small commercial customers (Fixed Transition Amount, or FTA, charges). FTA charges are authorized by the CPUC under state legislation and will be paid by residential and small commercial customers until the rate reduction bonds are fully retired. Under the terms of a transition property servicing agreement, FTA charges are collected by the Utility and remitted to PG&E Funding, LLC. As a result of credit rating downgrades in January 2001, on January 8, 2001, the Utility was required to begin remitting these FTA receipts to PG&E Funding, LLC on a daily basis, as opposed to once a month, as had previously been required.

The rate reduction bonds have expected maturity dates ranging from 2004 to 2007, and bear interest at rates ranging from 6.42% to 6.48%. The bonds are secured solely by the transition property and there is no recourse to the Utility or PG&E Corporation.

The total amount of rate reduction bonds principal outstanding was $1.16 billion at December 31, 2003 and $1.45 billion at December 31, 2002. The scheduled principal payments on the rate reduction bonds for the years 2004 through 2007 are $290 million for each year. While PG&E Funding, LLC is a wholly owned consolidated subsidiary of the Utility, it is legally separate from the Utility. The assets of PG&E Funding, LLC are not available to creditors of the Utility or PG&E Corporation, and the transition property is not legally an asset of the Utility or PG&E Corporation.

On July 8, 2003, NEGT filed a voluntary petition for relief under Chapter 11. The decline in wholesale electricity prices, NEGT’s construction program, the decline of NEGT’s credit rating to below investment grade, and lack of market liquidity created severe financial distress and ultimately caused it to seek protection under Chapter 11. As a result of NEGT’s Chapter 11 filing and the elimination of equity ownership provided for in NEGT’s proposed plan of reorganization, PG&E Corporation considers its investment in NEGT to be an abandoned asset and has accounted for NEGT as discontinued operations in accordance with SFAS No. 144. Under the provisions of SFAS No. 144, the operating results of NEGT and its subsidiaries are reported as discontinued operations in the Consolidated Statements of Operations through July 7, 2003 and for all prior years.

Effective July 8, 2003, NEGT and its subsidiaries are no longer consolidated by PG&E Corporation in its Consolidated Financial Statements. The accompanying December 31, 2003 Consolidated Balance Sheet of PG&E Corporation does not reflect the separate assets and liabilities of NEGT; rather, a liability of approximately $1.2 billion is reflected, which represents the losses of NEGT recognized by PG&E Corporation in excess of its investment in and advances to NEGT. In addition, accumulated other comprehensive income includes a net debit of approximately $77 million at December 31, 2003 related to NEGT. PG&E Corporation’s investment in NEGT will not be affected by changes in NEGT’s future financial results, other than (1) investments in or dividends from NEGT, or (2) income taxes PG&E Corporation may be required to pay if the IRS disallows certain deductions or tax credits related to NEGT or its subsidiaries for past tax years that are incorporated into PG&E Corporation’s consolidated tax returns.

Upon implementation of NEGT’s plan of reorganization or another plan that eliminates PG&E Corporation’s equity in NEGT, PG&E Corporation will reverse its investment in NEGT and the related amounts included in deferred income taxes and in accumulated other comprehensive income and, as a result, recognize a material one-time net non-cash gain to earnings from discontinued operations. The deferred tax assets arising from the losses related to NEGT or its subsidiaries that have been recognized through July 7, 2003 will reverse at the time PG&E Corporation releases its ownership interest in NEGT. This reversal of deferred tax assets will partially offset any one-time gain recognized when PG&E Corporation recognizes the gain related to its net investment in NEGT.

Included within earnings from discontinued operations on the Consolidated Statements of Operations of PG&E Corporation are NEGT’s operating results, summarized below:

Before PG&E Corporation began accounting for NEGT as discontinued operations, NEGT had accounted for certain of its subsidiaries as discontinued operations. The operating results shown above reflect the operating results of USGen New England, Inc. through July 7, 2003 and the other previously discontinued operations through the respective disposal dates. The 2003 pre-tax loss of NEGT and its subsidiaries includes the following gains and losses on disposal of those subsidiaries: a pre-tax gain of approximately $19 million on disposal related to the sale of Mountain View Power Partners, LLC in January 2003, an additional pre-tax loss of approximately $3 million on disposal related to the sale of PG&E Energy Trading, Canada Corporation in the first quarter of 2003, and a pre-tax loss of approximately $9 million on disposal related to the sale of certain Ohio generating plants and related equipment in the second quarter of 2003. Also included in the 2003 pre-tax loss of NEGT and its subsidiaries are impairments, write-offs, and other charges of approximately $229 million.

The 2002 pre-tax loss of NEGT and its subsidiaries includes the following gains and losses on disposal of subsidiaries: a pre-tax loss of approximately $25 million on the anticipated disposition of PG&E Energy Trading, Canada Corporation in the fourth quarter 2002, subsequently disposed of in 2003 as described above, and a $1.1 billion pre-tax loss for USGen New England deemed discontinued operations in the fourth quarter 2002. Also included in the 2002 pre-tax loss of NEGT and its subsidiaries are impairments, write-offs, and other charges of approximately $2.8 billion.

During the second quarter of 2003, NEGT determined that its historical financial reporting presentation of revenues and expenses related to hedging and certain ISO purchase and sales transactions had not been consistent. Certain types of transactions had been reported on a net basis (whereby revenues had been offset by the related expense item) and other types of transactions had been reported on a gross basis. In order to provide a consistent reporting of its trading and hedging transactions, NEGT adopted a net presentation approach for such transactions. PG&E Corporation believes that this method of presentation is preferable under the circumstances. Adopting this change reduced previously reported revenues and expenses of NEGT by approximately $843 million for the year ended December 31, 2002 and had no effect on the year ended December 31, 2001. In addition, adjustments were made principally for the effects of transactions that had not previously been eliminated in consolidation by NEGT. Such adjustments decreased previously reported revenues and expenses by approximately $671 million for the year ended December 31, 2002 and approximately $1.1 billion for the year ended December 31, 2001. These changes did not result in any change in consolidated operating income or net income, in the Consolidated Statements of Operations.

The following table reflects the condensed assets and liabilities of NEGT as reflected in current and noncurrent assets and liabilities in the accompanying Consolidated Balance Sheet of PG&E Corporation at December 31, 2002:

With its Chapter 11 filings, NEGT affiliates defaulted on numerous agreements. The amounts due as a result of these defaults will be determined and resolved in the context of NEGT Chapter 11 filings. PG&E Corporation is not a party to these agreements, nor does it anticipate any obligation related to these agreements.

PG&E Corporation has authorized 800 million shares of no-par common stock of which 416,520,282 shares were issued and outstanding at December 31, 2003 and 405,486,015 shares were issued and outstanding at December 31, 2002. A wholly owned subsidiary of PG&E Corporation holds 23,815,000 shares of the outstanding shares.

PG&E Corporation repurchased 34,037 shares of its common stock, at a cost of $528,691 during the year ended December 31, 2001 and 6,580 shares of its common stock, at a cost of $102,274, during the year ended December 31, 2002. There were no stock repurchases during the year ended December 31, 2003.

Of the 416,520,282 shares issued and outstanding at December 31, 2003, 1,535,268 shares are PG&E Corporation restricted stock granted by the Board of Directors on January 2, 2003 under the PG&E Corporation long-term incentive program. Further, PG&E Corporation issues common stock in connection with employee benefit plans (see Note 10).

PG&E Corporation has issued warrants to purchase 5,066,931 shares of its common stock at an exercise price of $0.01 per share to the lenders under prior credit agreements. At December 31, 2003, warrants to purchase 4,353,113 shares remained outstanding and were exercisable.

The Utility is authorized to issue 800 million shares of its $5 par value common stock, of which 321,314,760 shares were issued and outstanding as of December 31, 2003 and 2002. A wholly owned subsidiary of the Utility holds 19,481,213 of the outstanding shares. PG&E Corporation and PG&E Holding, LLC, a subsidiary of the Utility, hold all of the Utility’s outstanding common stock. Approximately 94% of the outstanding common stock of the Utility that is owned by PG&E Corporation has been pledged as security for PG&E Corporation’s 6 7/8% Senior Secured Notes of $600 million due 2008.

In October 2000, the Utility declared a $110 million common stock dividend to PG&E Corporation and PG&E Holding, LLC. In January 2001, the Utility suspended payment of the declared dividend.

The Utility did not declare or pay common and preferred stock dividends in 2001, 2002 or 2003. Until cumulative dividends on its preferred stock and mandatory preferred sinking fund payments are paid, the Utility may not pay any dividends on its common stock, nor may the Utility repurchase any of its common stock.

PG&E Corporation has authorized 85 million shares of preferred stock, which may be issued as redeemable or non-redeemable preferred stock. No preferred stock has been issued or is outstanding.

On December 20, 2000, the Board of Directors of PG&E Corporation declared a distribution of preferred stock purchase rights, or the Rights, at a rate of one Right for each share of PG&E Corporation common stock outstanding on January 2, 2001. The Board of Directors also authorized the issuance of one Right for each share of common stock issued by PG&E Corporation after January 2, 2001 and before the “distribution date” as described below. Each Right entitles the holder, in certain circumstances, to purchase from PG&E Corporation one one-hundredth of a share, or a Unit, of PG&E Corporation’s Series A Preferred Stock, par value $100 per share, at an initially fixed purchase price of $95 per Unit, subject to adjustment.

The Rights are not exercisable until the distribution date. The distribution date will occur upon the earlier of (1) 10 days following a public announcement that a person or group (other than PG&E Corporation, any of its subsidiaries, or its employee benefit plans) has acquired or obtained the right to acquire beneficial ownership of 15% or more of the then-outstanding shares PG&E Corporation common stock and (2) 10 business days (or later, as determined by the Board of Directors) following the commencement of a tender offer or exchange offer that would result in a person or group owning 15% or more of the then-outstanding shares of PG&E Corporation common stock. After the distribution date, certain triggering events will enable the holder of each Right (other than a potential acquirer) to purchase Units of Series A Preferred Stock having twice the market value of the initially fixed exercise price, i.e., at a 50% discount. Until a Right is exercised, the holder will not have any rights as a shareholder of PG&E Corporation, including without limitation the right to vote or to receive dividends.

As originally approved by the Board of Directors, the Rights would expire on December 22, 2010, unless redeemed earlier by the PG&E Corporation Board of Directors. On February 18, 2004, the Board of Directors adopted an amendment providing that the Rights will expire on the effective date of the Utility’s Plan of Reorganization, unless otherwise redeemed earlier by the PG&E Corporation Board of Directors.

A total of 5,000,000 shares of preferred stock have been reserved for issuance upon exercise of the Rights. The Units of preferred stock that may be acquired upon exercise of the Rights will be non-redeemable and subordinate to any other shares of preferred stock that may be issued by PG&E Corporation. Each Unit of preferred stock will have a minimum preferential quarterly dividend rate of $0.01 per Unit but will, in any event, be entitled to a dividend equal to the per share dividend declared on the common stock. In the event of liquidation, the holder of a Unit will receive a preferred liquidation payment.

The Rights also have certain anti-takeover effects and will cause substantial dilution to a person or group that attempts to acquire PG&E Corporation on terms not approved by PG&E Corporation’s Board of Directors, unless the offer is conditioned on a substantial number of Rights being acquired. The Rights should not interfere with any approved merger or other business combination, as the Board of Directors, at its option, may redeem the Rights. Thus, the Rights are intended to encourage persons who may seek to acquire control of PG&E Corporation to initiate such an acquisition through negotiations with PG&E Corporation’s Board of Directors.

The Utility has authorized 75 million shares of $25 par value preferred stock, which may be issued as redeemable or non-redeemable preferred stock.

At December 31, 2003 and 2002, the Utility had issued and outstanding 5,784,825 shares of non-redeemable preferred stock. Holders of the Utility’s 5.0%, 5.5% and 6.0% series of non-redeemable preferred stock have rights to annual dividends ranging from $1.25 to $1.50 per share.

At December 31, 2003 and 2002, the Utility had issued and outstanding 5,973,456 shares of redeemable preferred stock. The Utility’s redeemable preferred stock is subject to redemption at its option, in whole or in part, if the Utility pays the specified redemption price plus accumulated and unpaid dividends through the redemption date. At December 31, 2003, annual dividends ranged from $1.09 to $1.76 per share and redemption prices ranged from $25.75 to $27.25 per share.

At December 31, 2003, the Utility’s redeemable preferred stock with mandatory redemption provisions consisted of 3 million shares of the 6.57% series and 2.5 million shares of the 6.30% series. These series are redeemable at par value plus accumulated and unpaid dividends through the redemption date. These series of preferred stock are subject to mandatory redemption provisions entitling them to sinking funds providing for the retirement of the stock outstanding.

The redemption requirements for the Utility’s redeemable preferred stock with mandatory redemption provisions for the 6.57% series are approximately $4 million per year from 2002 through 2006, and approximately $55 million in 2007, and for the 6.30% series, approximately $3 million per year from 2004 through 2008, and approximately $47 million in 2009. The Utility’s redeemable preferred stock with mandatory redemption provisions may be redeemed early, at the Utility’s option, if the Utility pays the specified redemption price plus accumulated and unpaid dividends.

Due to the Utility’s Chapter 11 proceeding, the Utility’s Board of Directors has not declared or paid preferred stock dividends since January 31, 2001. Dividends on all Utility preferred stock are cumulative. All shares of preferred stock have voting rights and an equal preference in dividend and liquidation rights. Accumulated and unpaid preferred stock dividends amounted to approximately $80 million as of December 31, 2003, $50 million as of December 31, 2002 and $25 million as of December 31, 2001. Upon liquidation or dissolution of the Utility, holders of preferred stock would be entitled to the par value of such shares plus all accumulated and unpaid dividends, as specified for the class and series.

As discussed above in Note 1 under “Adoption of New Accounting Policies — Accounting for Financial Instruments with Characteristics of Both Liabilities and Equity,” PG&E Corporation and the Utility adopted the requirements of SFAS No. 150 in the third quarter of 2003. As a result, the Utility reclassified approximately $137 million of preferred stock with mandatory redemption provisions as a noncurrent liability in the Utility’s Consolidated Balance Sheets. The reclassification did not have an impact on earnings of PG&E Corporation or the Utility.

As discussed in Note 5, NEGT financial results are no longer consolidated with those of PG&E Corporation following the July 8, 2003 Chapter 11 filing of NEGT. NEGT’s financial results through July 7, 2003 are reflected in discontinued operations. Because NEGT financial results are no longer consolidated with those of PG&E Corporation, the only risk management activities currently reported by PG&E Corporation are related to Utility non-trading activities.

On the Utility’s Consolidated Balance Sheets, cash flow hedges associated with natural gas commodity price risk are presented at a fair value of $4 million in other current assets. Unrealized losses associated with these cash flow hedges are recorded in regulatory accounts. The natural gas cash flow hedges have varying durations, the longest of which extend through March 2004.

Cash flow hedges associated with interest rate risk are presented at fair value in other current assets. For the portion of the cash flow hedges associated with regulated operations and subject to the provisions of SFAS No. 71, the effective and ineffective portions are recorded in regulatory assets. For the portion of hedges related to non-regulated

The following table presents selected information related to cash flow hedges associated with the interest rate risk related to non-regulated operations at December 31, 2003:

The actual amounts reclassified upon the contractual terms of the contracts or the termination of the hedge position will differ from the expected amounts presented above as a result of changes in interest rates. At December 31, 2002 the Utility did not have any cash flow hedges.

The ineffective portion of changes in amounts of the Utility’s cash flow hedges was approximately $4 million for the year ended December 31, 2003. There was no ineffective portion of changes in amounts of the Utility’s cash flow hedges for the year ended December 31, 2002.

The Utility has certain non-trading derivative instruments for the purchase of electricity, natural gas and natural gas transportation and storage that are exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception and thus have no mark-to-market effect on earnings. Additionally, the Utility holds an immaterial amount of other non-trading derivative instruments that do not qualify for cash flow hedge accounting or the normal purchase and sales exception to SFAS No. 133. These derivative instruments are reported in earnings on a mark-to-market basis.

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if customers or counterparties failed to perform their contractual obligations.

PG&E Corporation had gross accounts receivable of approximately $2.5 billion at December 31, 2003 and $2.0 billion at December 31, 2002. The majority of the accounts receivable are associated with the Utility’s residential and small commercial customers. Based upon historical experience and evaluation of then-current factors, allowances for doubtful accounts of approximately $68 million at December 31, 2003 and $59 million at December 31, 2002 were recorded against those accounts receivable. In accordance with tariffs, credit risk exposure is limited by requiring deposits from new customers and from those customers whose past payment practices are below standard. The Utility has a regional concentration of credit risk associated with its receivables from residential and small commercial customers in northern and central California. However, material loss due to non-performance from these customers is not considered likely.

The Utility manages credit risk for its largest customers or counterparties by assigning credit limits based on an evaluation of their financial condition, net worth, credit rating, and other credit criteria as deemed appropriate. Credit limits and credit quality are monitored frequently and a detailed credit analysis is performed at least annually.

Credit exposure for the Utility’s largest customers and counterparties is calculated daily. If exposure exceeds the established limits, the Utility takes immediate action to reduce the exposure, or obtain additional collateral, or both. Further, the Utility relies heavily on master agreements that require security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

The Utility calculates gross credit exposure for each of its largest customers and counterparties as the current mark-to-market value of the contract (i.e., the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, before the application of credit collateral. During 2003 the Utility recognized no material losses due to contract defaults or bankruptcies. At December 31, 2003 there were three counterparties that represented greater than 10% of the Utility’s net credit exposure. The Utility had two investment grade counterparties that represented a total of approximately 32% of the Utility’s net credit exposure and one below-investment grade counterparty that represented approximately 12% of the Utility’s net credit exposure.

The schedule below summarizes the Utility’s net asset credit risk exposure, as well as the Utility’s credit risk exposure to its largest customers or counterparties with a greater than 10% net credit exposure, at December 31, 2003 and December 31, 2002. Credit exposures to Enron subsequent to its filing for Chapter 11 are not included in the information below. See Note 12 for discussion of the Enron Settlement.


⁽¹⁾	Gross credit exposure equals mark-to-market value, notes receivable and net receivables (payables) where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity or credit reserves. The Utility’s gross credit exposure includes wholesale activity only. Retail activity and payables incurred prior to the Utility’s Chapter 11 filing are not included. Retail activity at the Utility consists of the accounts receivable from the sale of natural gas and electricity to residential and small commercial customers.

⁽²⁾	Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

The schedule below summarizes the credit quality of the Utility’s net credit risk exposure to the Utility’s largest customers and counterparties at December 31, 2003 and December 31, 2002:


⁽¹⁾	Credit ratings are determined by using publicly available information. If provided a guarantee by a higher rated entity (e.g., an affiliate), the rating is determined based on the rating of the guarantor.

⁽²⁾	Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit). For purposes of this table, parental guarantees are not included as part of the calculation.

⁽³⁾	Investment grade is determined using publicly available information, i.e., rated at least Baa3 by Moody’s and BBB- by S&P. The Utility has assessed certain governmental authorities that are not rated through publicly available information as investment grade based upon an internal assessment of credit quality.

Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility’s nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040. Decommissioning of Diablo Canyon Unit 2 is

The estimated nuclear decommissioning cost for the Diablo Canyon power plant and Humboldt Bay Unit 3 is approximately $1.83 billion in 2003 dollars (or approximately $5.25 billion in future dollars). These estimates are based on a 2002 decommissioning cost study, prepared in accordance with CPUC requirements and used in the Utility’s Nuclear Decommissioning Costs Triennial Proceeding, which is discussed below. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear plants. Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment.

The estimated nuclear decommissioning cost described above is used for regulatory purposes. However, under GAAP requirements, the decommissioning cost estimate is calculated using a different method. As discussed above in Note 1 under “Adoption of New Accounting Policies — Accounting for Asset Retirement Obligations,” on January 1, 2003 the Utility adopted SFAS No. 143, a GAAP requirement. Under SFAS No. 143, the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities. In addition, the Utility records the Utility’s total nuclear decommissioning obligation as an asset retirement obligation (previously recorded in accumulated depreciation and decommissioning) on the Utility’s Consolidated Balance Sheet. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.1 billion at December 31, 2003 and $1.3 billion at December 31, 2002.

The CPUC has established the Nuclear Decommissioning Costs Triennial Proceeding to determine the Utility’s estimated decommissioning costs and to establish the associated annual revenue requirement and escalation factors for consecutive three-year periods. In October 2003, the CPUC issued a decision in the 2002 Nuclear Decommissioning Costs Triennial Proceeding (covering 2003 through 2005) finding that the funds in the Diablo Canyon nuclear decommissioning trusts are sufficient to pay for the Diablo Canyon power plant’s eventual decommissioning. The decision also set the annual decommissioning fund revenue requirement for Humboldt Bay Unit 3 at approximately $18.5 million and granted the Utility’s request to begin decommissioning Humboldt Bay Unit 3 in 2006 instead of 2015. The decision further granted the Utility’s request of approximately $8.3 million for Humboldt Bay Unit 3 SAFSTOR operating and maintenance costs, with escalation adjustments of approximately $218,000 in 2004 and $230,000 in 2005. SAFSTOR is a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The total adopted annual revenue requirement of approximately $26.7 million represents a decrease of approximately $4.5 million from the previously adopted revenue requirement of approximately $31.2 million which included amounts for both Humboldt Bay Unit 3 and Diablo Canyon. The CPUC also ordered the Utility to partially fund its 2004 revenue requirement with approximately $10 million that the Utility collected in rates in 2000 for its nuclear decommissioning revenue requirement, but that the Utility did not contribute to the trusts due to the Utility’s cash conservation needs during the energy crisis.

The Utility’s revenue requirements for nuclear decommissioning costs are recovered from ratepayers through a non-bypassable charge that will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from ratepayers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts’ after-tax returns. Among other requirements, to maintain the qualified trust status the IRS must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until such decommissioning costs are actually incurred.

In 2003, the Utility collected approximately $22.6 million in rates and contributed approximately $21.3 million, on an after-tax basis, to the nuclear decommissioning trusts. For 2004, the Utility is authorized to collect approximately $18.5 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, the Utility expects to contribute approximately $13.3 million, on an after-tax basis, to the qualified and non-qualified trusts for Humboldt Bay Unit 3. The Utility has requested the IRS approve the new amounts to be contributed to the qualified trusts for Humboldt Bay Unit 3. If the IRS does not approve the request, the Utility must withdraw any contributions it made to the qualified trusts for 2003 and contribute the withdrawn amounts, on an after-tax basis, to the non-qualified trust. The Utility would likely request that the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes.

The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’s nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. The CPUC has authorized the CPUC qualified trust to invest a maximum of 50% of its funds in publicly traded equity securities, of which up to 20% may be invested in publicly traded non-US equity securities. For the CPUC non-qualified trust, no more than 60% may be invested in publicly traded equities. The allocation of the trust funds is monitored monthly. To the extent that market movements cause the asset allocation to move outside these ranges, the investments are rebalanced toward the target allocation.

The Utility estimates after-tax annual earnings, including realized gains and losses, in the qualified trusts to range from 4.16% to 6.69% and in the non-qualified trusts to range from 3.79% to 5.97%. Annual returns decrease in later years as higher portions of the trusts are dedicated to fixed income investments leading up to and during the entire course of decommissioning activities.

All earnings on the assets held in the trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. At December 31, 2003, the Utility had accumulated nuclear decommissioning trust funds with an estimated fair value of approximately $1.4 billion, based on quoted market prices and net of deferred taxes on unrealized gains.

In general, investment securities are exposed to various risks, such as interest rate, credit and market volatility risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the market values of investment securities could occur in the near term, and such changes could materially affect the trusts’ current value.

The Utility accounts for its investments held in trusts as assets held for sale in accordance with SFAS No. 115, “Accounting for Certain Investments in Debt and Equity Securities.” Realized gains and losses are recognized as additions or reductions to trust asset balances. Unrealized gains and losses are recorded in regulatory asset or liability accounts in accordance with SFAS No. 71.

The following table provides a summary of the fair value, based on quoted market prices, of the investments held in the Utility’s nuclear decommissioning trusts:

The cost of debt and equity securities sold is determined by specific identification. The following table provides a summary of the activity for the debt and equity securities:

Under the Nuclear Waste Policy Act of 1982, the U.S. Department of Energy, or DOE, is responsible for the permanent storage and disposal of spent nuclear fuel. The Utility has signed a contract with the DOE to provide for the disposal of spent nuclear fuel and high-level radioactive waste from the Utility’s nuclear power facilities. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. The DOE’s current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. However, considerable uncertainty exists regarding when the DOE will begin to accept spent fuel for storage or disposal. Under the Utility’s contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon’s spent fuel would be accepted for storage or disposal would be 2018. At the projected level of operation for Diablo Canyon, the Utility’s facilities are able to store on-site all spent fuel produced through approximately 2007. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon’s spent fuel by 2007. Therefore, the Utility has applied to the NRC for authorization to store spent fuel in an on-site dry cask storage facility. The NRC has provided initial approval for the facility and is expected to complete its authorization process in early 2004. The Utility has also initiated the process to obtain the required California Coastal Commission permit for this facility. If the dry cask storage facility is not approved or is delayed, the Utility also is pursuing NRC approval of another storage option to install a temporary rack in each unit that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. During this additional period of time, the Utility also would pursue NRC approval for a high density reracking of both units, which, if approved, would allow the Utility to operate both units until shortly before the licenses expire in 2021 for Unit 1 and 2024 for Unit 2. If the Utility is unsuccessful in permitting and constructing the on-site dry cask storage facility, and 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 until such time as spent fuel can be safely stored.

PG&E Corporation and its subsidiaries provide non-contributory defined benefit pension plans for their employees and retirees (referred to collectively as pension benefits). PG&E Corporation and the Utility have elected that certain of the trusts underlying these plans be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, PG&E Corporation and the Utility are allowed a deduction for payments made to the qualified trusts, subject to certain Internal Revenue Code limitations. PG&E Corporation and its subsidiaries also provide contributory defined benefit medical plans for certain retired employees and their eligible dependents, and non-contributory defined benefit life insurance plans for certain retired employees (referred to collectively as other benefits). The following schedules aggregate all PG&E Corporation’s and the Utility’s plans. As discussed in Note 5, NEGT financial results are no longer consolidated in those of PG&E Corporation following the July 8, 2003 Chapter 11 filing of NEGT. Accordingly, pension and other benefits information is disclosed below for plans that PG&E Corporation and the Utility sponsor at December 31, 2003. However, NEGT pension and other benefits information after December 31, 2002 is not disclosed below. PG&E Corporation and its subsidiaries use a December 31 measurement date for all of its plans.

The following reconciles changes in aggregate projected benefit obligations for pension benefits and changes in the benefit obligation of other benefits during 2003 and 2002:

PG&E Corporation has participants in the Utility’s Retirement Plan, Retirement Excess Benefit Plan and the Supplemental Executive Retirement Plan. PG&E Corporation’s obligation for its participants in these plans was approximately $15 million at December 31, 2003 and $10 million at December 31, 2002, and is recorded as a liability in PG&E Corporation’s Balance Sheets.

PG&E Corporation has participants in the Utility’s Postretirement Medical Plan and Postretirement Life Insurance Plan. PG&E Corporation’s obligation for its participants in these plans was approximately $1 million at December 31, 2003 and $1 million at December 31, 2002, and is recorded as a liability in PG&E Corporation’s Balance Sheets.

PG&E Corporation and the Utility use publicly quoted market values and independent pricing services depending on the nature of the assets, as reported by the trustee to determine the fair value of the plan assets.

The following schedule reconciles the plans’ aggregate funded status to the prepaid or accrued benefit cost recorded on PG&E Corporation’s and the Utility’s Consolidated Balance Sheets. The funded status is the difference between the fair value of plan assets and projected benefit obligations.

The separate prepaid benefit costs and accrued benefit liabilities of PG&E Corporation’s pension and other benefit plans were as follows:

The aggregate projected benefit obligation, accumulated benefit obligation and fair value of plan assets for plans in which the fair value of plan assets are less than either the projected benefit obligation or accumulated benefit obligation were as follows:

The following actuarial assumptions were used in determining the projected benefit obligations and the net periodic cost. Weighted average, year-end assumptions were used in determining the plans’ projected benefit obligations, while prior year-end assumptions are used to compute net benefit cost.

The assumed health care cost trend rate for 2004 is approximately 9.5%, grading down to an ultimate rate in 2008 and beyond of approximately 5.5%. A one-percentage point change in assumed health care cost trend rate would have the following effects:

The difference between actual and expected return on plan assets is included in net amortization and deferral, and is considered in the determination of future net benefit income (cost). The actual return on plan assets was above the expected return in 2003, and below the expected return for 2002 and 2001.

Under SFAS No. 71, regulatory adjustments have been recorded in the Consolidated Statements of Operations and Consolidated Balance Sheets of the Utility to reflect the difference between Utility pension expense or income for accounting purposes and Utility pension expense or income for ratemaking, which is based on a funding approach. The CPUC has authorized the Utility to recover the costs associated with its other benefits for 1993 and beyond. Recovery

The asset allocation of PG&E Corporation’s and the Utility’s pension and other benefit plans at December 31, 2003 and 2002, and target 2004 allocation was as follows:

Equity securities include a small amount (less than 0.1% of total plan assets) of PG&E Corporation common stock.

The maturity of debt securities at December 31, 2003 and 2002 ranges from 1 to 46 years, with a weighted average maturity of 7 years.

PG&E Corporation’s and the Utility’s investment strategy for all plans is to maintain actual asset weightings within 5% of the target asset allocations. Whenever the actual weighting exceeds the target weighting by 5%, the asset holdings are rebalanced.

A benchmark portfolio for each asset class is set based on market capitalization and valuations of equities and the durations and credit quality of debt securities. Investment managers for each asset class are retained to periodically adjust, or actively manage, the combined portfolio against the benchmark. Active management covers approximately 50% of the U.S. equity, 80% of the non-U.S. equity and virtually 100% of the debt security portfolios.

PG&E Corporation and the Utility expect to contribute up to $129 million to its Pension Benefits Plan, assuming favorable resolution of pension related rate recovery in the 2003 GRC, and approximately $65 million to its Other Benefits Plan in 2004. These contributions would be consistent with PG&E Corporation’s and the Utility’s funding policy, which is to contribute amounts that are tax deductible, consistent with applicable regulatory decisions and sufficient to meet minimum funding requirements. None of these benefit plans are subject to a minimum funding requirement in 2004.

PG&E Corporation and its subsidiaries also sponsor defined contribution pension plans. These plans are qualified under applicable sections of the Internal Revenue Code. These plans provide for tax-deferred salary deductions and after-tax employee contributions as well as employer contributions. Employees designate the funds in which their contributions and any employer contributions are invested. Employer contributions include matching of up to 5% of an employee’s base compensation and/or basic contributions of up to 5% of an employee’s base compensation. For certain plans, matching employer contributions are automatically invested in PG&E Corporation common stock. Employees may reallocate matching employer contributions and accumulated earnings thereon to another investment fund or funds available to the plan at any time once they have been credited to their account. Employer contribution expense reflected in PG&E Corporation’s Consolidated Statements of Operations amounted to:

PG&E Corporation maintains a long-term incentive program, or LTIP, that permits stock options, restricted stock and other stock-based incentive awards to be granted to non-employee directors, executive officers and other employees of PG&E Corporation and its subsidiaries. Stock options can be granted with or without associated stock appreciation rights and dividend equivalents.

At December 31, 2003, a total of 40,130,988 shares of PG&E Corporation common stock had been authorized for award under the LTIP, with 12,714,608 shares still available for grant.

The weighted average grant date fair values of options granted using the Black-Scholes valuation method were $7.27 per share in 2003, $6.60 per share in 2002, and $6.01 and $5.80 per share in 2001, using two sets of assumptions. Significant assumptions used in the Black-Scholes valuation method for shares granted in 2003, 2002, and 2001 (two sets of assumptions) were:

Stock options issued after January 2003 become exercisable on a cumulative basis at one-fourth each year commencing one year from the date of the grant. Stock options issued before January 2003 become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant. All options expire ten years and one day after the date of grant. Options outstanding at December 31, 2003, had option prices ranging from $11.80 to $34.25, and a weighted average remaining contractual life of 6.13 years.

The following table summarizes stock option activity for the years ended December 31:

The following summarizes information for options outstanding and exercisable at December 31, 2003. Of the outstanding options at December 31, 2003:


	•	11,436,557 options had exercise prices ranging from $11.80 to $16.68, with a weighted average remaining contractual life of 7.87 years, of which 2,177,155 shares were exercisable at a weighted average exercise price of $14.51;

	•	7,193,916 options had exercise prices ranging from $19.45 to $26.75, with a weighted average remaining contractual life of 5.41 years, of which 5,130,090 shares were exercisable at a weighted average exercise price of $20.94; and

	•	8,785,907 options had exercise prices ranging from $27.13 to $34.25, with a weighted average remaining contractual life of 4.46 years, of which 8,765,409 shares were exercisable at a weighted average exercise price of $30.61.

In addition, 2,437,600 options were granted on January 2, 2004 at an exercise price of $27.23, the then-current market price of PG&E Corporation common stock.

Stock options outstanding to purchase PG&E Corporation common stock held by Utility employees at December 31, 2003 had option prices ranging from $12.63 to $34.25, and a weighted average remaining contractual life of 6.19 years. The following table summarizes the stock option activity for the Utility employees for the years ended December 31:

The following summarizes information for options outstanding and exercisable at December 31, 2003. Of the outstanding options at December 31, 2003:


	•	5,995,290 options had exercise prices ranging from $12.63 to $16.68, with a weighted average remaining contractual life of 7.93 years, of which 1,113,239 options were exercisable at a weighted average exercise price of $14.41;

	•	3,210,388 options had exercise prices ranging from $19.81 to $26.31, with a weighted average remaining contractual life of 5.46 years, of which 2,218,165 options were exercisable at a weighted average exercise price of $20.52; and

	•	4,337,504 options had exercise prices ranging from $28.35 to $34.25, with a weighted average remaining contractual life of 4.33 years, of which 4,337,504 options were exercisable at a weighted average exercise price of $30.59.

In addition, 1,638,500 options were granted to Utility employees on January 2, 2004 at an exercise price of $27.23, the then-current market price of PG&E Corporation common stock.

On January 2, 2003, a total of 1,574,410 shares of restricted PG&E Corporation common stock was awarded to eligible employees of PG&E Corporation and its subsidiaries, of which 934,630 shares were granted to Utility employees. The shares were granted with restrictions and are subject to forfeiture unless certain conditions are met.

The restricted shares are held in an escrow account. The shares become available to the employees as the restrictions lapse. For restricted stock granted in 2003, the restrictions on 80% of the shares lapse automatically over a period of four years at the rate of 20% per year. The compensation expense for these shares remains fixed at the value of the stock at grant date. Restrictions on the remaining 20% of the shares will lapse at a rate of 5% per year if PG&E Corporation is in the top quartile of its comparator group, as measured by annual total shareholder return for each year ending immediately before each annual lapse date. The compensation expense recognized for these shares is variable and changes with the common stock’s market price.

Compensation expense associated with all the shares is recognized on a quarterly basis, by amortizing the unearned compensation related to that period. Total compensation expense resulting from the restricted stock issuance reflected on PG&E Corporation’s Consolidated Statements of Operations was approximately $7.1 million in 2003, of which approximately $4.4 million was recognized by the Utility. The total unamortized balance of unearned compensation resulting from the restricted stock issuance reflected on PG&E Corporation’s Consolidated Balance Sheets was approximately $20 million at December 31, 2003. On January 2, 2004, PG&E Corporation awarded

PG&E Corporation has granted performance units to certain officers and employees of PG&E Corporation and its subsidiaries. The performance units, subject to the achievement of certain performance targets, vest one-third per year and are settled in cash annually as vesting occurs in each of the three years following the year of grant. The number of performance units that were outstanding at December 31, 2003 was 318,256. The amount of compensation expense recognized in connection with the issuance of performance units was approximately $11 million in 2003. The amount of compensation expense recognized in 2002 and 2001 was not material. No performance units were granted in 2004.

On January 2, 2004, PG&E Corporation awarded 495,900 performance shares, or phantom stock, of which 333,110 were awarded to Utility employees. The performance shares, subject to the achievement of certain performance targets, vest one-third per year and will be settled annually as vesting occurs in each of the three years following the date of the grant.

The supplemental retirement savings plan provides supplemental retirement alternatives to eligible officers and key employees of PG&E Corporation and its subsidiaries by allowing participants to defer portions of their compensation, including salaries and amounts awarded under various incentive awards, and to receive supplemental employer-provided retirement benefits. Under the employee-elected deferral component of the plan, eligible employees may defer all or part of their incentive awards, and 5% to 50% of their salary. Under the supplemental employer-provided retirement benefits component of the plan, eligible employees may receive full credit for employer matching and basic contributions, under the respective defined contribution plan, in excess of limitations set out by the Internal Revenue Code. A separate non-qualified account is maintained for each eligible employee to track deferred amounts. The account’s value is adjusted in accordance with the performance of the investment options selected by the employee. PG&E Corporation adjusts each employee’s account on a quarterly basis and records additional compensation expense or income in its financial statements. Total compensation expense recognized by PG&E Corporation in connection with the plan amounted to approximately $7 million for the year ended December 31, 2003, of which approximately $1 million was recognized by the Utility. PG&E Corporation recognized compensation expense of approximately $2 million for the year ended December 31, 2002, with no comparable amount for the Utility. For the year ended December 31, 2001 the compensation expense recognized in connection with the plan was not material.

PG&E Corporation implemented various retention programs in 2001. One of these programs granted key personnel of PG&E Corporation and its subsidiaries with lump-sum cash payments. In addition, another program granted units of special senior executive retention grants.

These grants provided certain employees with PG&E Corporation phantom restricted stock units that vested in full on December 31, 2003 upon PG&E Corporation meeting certain performance measures at that date. A total of 3,044,600 phantom stock units were granted under this program. These units were marked to market based on the market price of PG&E Corporation common stock and amortized as a charge to income over a four-year period. As a result of meeting the performance criteria at December 31, 2003 these units fully vested and the remaining compensation expense was recognized in 2003. Total compensation expense recognized in connection with these retention mechanisms, including cash payments and phantom restricted stock units, amounted to:

In January 2004, approximately $84.5 million was paid to participating individuals in the senior executive retention program. There are no payments remaining under either plan.

The significant components of income tax (benefit) expense for continuing operations were:

The differences between income taxes and amounts calculated by applying the federal legal rate to income before income tax expense for continuing operations were:

At December 31, 2003, PG&E Corporation had $420 million of California net operating loss, or NOL, carryforwards that will expire if not used by the end of 2012. The California Revenue and Taxation Code has suspended the use of NOL carryforwards for the tax years ending December 31, 2003 and December 31, 2002.

In 2002, PG&E Corporation established valuation allowances for state deferred tax assets associated with the impairments and write-offs related to NEGT and its subsidiaries. A valuation allowance of approximately $184 million was recorded in discontinued operations with respect to state deferred tax assets associated with impairments and write-offs reflected in discontinued operations. These valuation allowances were established due to the uncertainty in realizing tax benefits associated with the state deferred tax assets. PG&E Corporation could not determine that it was more likely than not that some portion or all of its state deferred tax assets would be realized.

In 2003, PG&E Corporation increased its valuation allowance due to the uncertainty in realizing certain state deferred tax assets related to NEGT or its subsidiaries. Valuation allowances of approximately $24 million were recorded in discontinued operations, and approximately $5 million in accumulated other comprehensive loss for the year ended December 31, 2003.

Effective July 8, 2003, PG&E Corporation adopted the cost method of accounting for its ownership interest in NEGT. PG&E Corporation will not recognize additional income tax benefits for financial statement reporting purposes after July 7, 2003 with respect to any losses related to NEGT or its subsidiaries even though it continues to include NEGT and its subsidiaries in its consolidated income tax returns. Any such unrealized benefits and deferred tax assets arising from losses related to NEGT or its subsidiaries that have been recognized through July 7, 2003 will be recorded in discontinued operations in the Consolidated Statements of Operations at the time that PG&E Corporation releases its ownership interest in NEGT.

PG&E Corporation and the Utility have substantial financial commitments and contingencies in connection with agreements entered into supporting the Utility’s operating activities. PG&E Corporation has limited financial commitments relating to NEGT’s operating activities.

Qualifying Facility Agreements – The Utility is required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. Under PURPA, the CPUC required California investor-owned electric utilities to enter into a series of long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, price options and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility’s actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility’s total available capacity and contractual capacity commitment.

As a result of the energy crisis, the Utility owed approximately $1 billion to qualifying facilities when it filed its Chapter 11 petition. Through December 31, 2003, the principal payments made to the qualifying facilities amounted to $998 million.

At December 31, 2003, the Utility had agreements with 300 qualifying facilities for approximately 4,400 megawatts, or MW, that are in operation. Agreements for approximately 4,000 megawatts expire between 2004 and 2028. Qualifying facility power purchase agreements for approximately 400 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. The Utility also has agreements with 50 qualifying facilities that are not currently providing or expected to provide electricity. The total of approximately 4,400 MW consists of approximately 2,600 MW from cogeneration projects, 800 MW from wind projects and 1,000 MW from other projects, including biomass, waste-to-energy, geothermal, solar and hydroelectric. On January 22, 2004, the CPUC adopted a decision that requires California investor-owned electric utilities to allow owners of qualifying facilities with power purchase agreements expiring before the end of 2005 to extend these contracts for five years. Qualifying facility power purchase agreements accounted for approximately 20% of the Utility’s 2003 electricity sources, approximately 25% of the Utility’s 2002 electricity sources, and approximately 21% of the Utility’s 2001 electricity resources. No single qualifying facility accounted for more than 5% of the Utility’s 2003, 2002 or 2001 electricity sources.

In a proceeding pending at the CPUC, the Utility has requested refunds in excess of $500 million for overpayments from June 2000 through March 2001 made to qualifying facilities. Under the Settlement Agreement, the net after-tax amount of any qualifying facilities refunds, which the Utility actually realizes in cash, claim offsets or other credits, would reduce the $2.21 billion after-tax regulatory asset. While PG&E Corporation and the Utility are unable to estimate the outcome of this proceeding they believe the proceeding will not have a material adverse effect on their financial condition or results of operations.

Irrigation Districts and Water Agencies – The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts’ and water agencies’ debt service requirements, regardless if any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. The Utility’s irrigation district and water agency contracts accounted for approximately 5% of 2003 electricity sources, approximately 4% of 2002 electricity sources and approximately 3% of 2001 electricity sources.

Electricity Purchases to Satisfy the Residual Net Open Position – On January 1, 2003, the Utility resumed buying electricity to meet its residual net open position. During that year, more than 14,000 GWh of energy was bought and sold in the wholesale market to manage the 2003 residual net open position. Most of the Utility’s contracts entered into in 2003 had terms of less than one year. During 2004 the Utility plans to enter into contracts of longer duration to satisfy its near-term residual net open position.

Renewable Energy Requirement – California law requires that, beginning in 2003, each California investor-owned electric utility must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility estimates the annual procurement target will initially require it to purchase about 750 Gigawatt-hours, or GWh, of electricity from renewable resources each year. The Utility met its 2003 commitment and the CPUC has approved several contracts intended to meet its 2004 renewable energy requirement.

Annual Receipts and Payments – The amount of electricity received and the total payments made under qualifying facility, irrigation district, water agency and bilateral agreements during 2001 through 2003 were as follows:

At December 31, 2003, the undiscounted future expected power purchase agreement payments were as follows:

As a result of the Utility’s Chapter 11 filing and its credit rating being below investment grade, it uses several different credit arrangements to purchase natural gas, including a $10 million cash collateralized standby letter of credit and a pledge of its core natural gas customer accounts receivable. The core natural gas inventory also may be pledged, but only if the amount of the Utility’s natural gas customer accounts receivable is less than the amount that it owes to natural gas suppliers. To date, the Utility’s accounts receivable pledge has been sufficient. The pledged amounts were approximately $561 million at December 31, 2003 and $513 million at December 31, 2002. It is anticipated that the pledge of natural gas customer accounts receivable and natural gas inventory will be replaced with letters of credit no later than the effective date of the Plan of Reorganization.

The Utility also has long-term gas transportation service agreements with various Canadian and interstate pipeline companies. These companies are responsible for transporting the Utility’s gas to the California border. These agreements include provisions for payment of fixed demand charges for reserving firm pipeline capacity as well as volumetric transportation charges. The total demand charges that the Utility will pay each year may change periodically as a result of changes in regulated tariff rates. The total demand (net of sales of excess supplies) and volumetric transportation charges the Utility incurred under these agreements were approximately $131 million in 2003, $101 million in 2002 and $239 million in 2001.

At December 31, 2003, the Utility’s obligations for natural gas purchases and gas transportation services were as follows:

The Utility has purchase agreements for nuclear fuel. These agreements have terms ranging from two to five years and are intended to ensure long-term fuel supply. Deliveries under nine of the eleven contracts in place at the end of 2003 will end by 2005. In most cases, the Utility’s nuclear fuel contracts are requirements-based. The Utility relies on large, well-established international producers of nuclear fuel in order to diversify its commitments and provide security of supply. Pricing terms are also diversified, ranging from fixed prices to base prices that are adjusted using published information.

At December 31, 2003, the undiscounted obligations under nuclear fuel agreements were as follows:

Payments for nuclear fuel amounted to approximately $57 million in 2003, $70 million in 2002 and $50 million in 2001.

In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnection of the Utility’s and WAPA’s electricity transmission systems, the use of the Utility’s electricity transmission and distribution system by WAPA, and the integration of the Utility’s and WAPA’s customer demands and electricity resources. The contracts give the Utility access to WAPA’s excess hydroelectric power and obligate the Utility to provide WAPA with electricity when its own resources are not sufficient to meet its requirements. The contracts are scheduled to terminate on December 31, 2004, but termination is subject to FERC approval, which the Utility expects to receive.

The costs to fulfill the Utility’s obligations to WAPA under the contracts cannot be accurately estimated at this time since both the purchase price and the amount of electricity WAPA will need from the Utility in 2004 are uncertain. However, the Utility expects that the cost of meeting its contractual obligations to WAPA will be greater than the price the Utility receives from WAPA under the contracts. Although it is not indicative of future sales commitments or sales-related costs, WAPA’s net amount purchased from the Utility was approximately 4,804 GWh, in 2003, 3,619 GWh in 2002 and 4,823 GWh in 2001.

The Utility is a party to a Transmission Control Agreement, or TCA, with the ISO and other participating transmission owners. As a transmission owner, the Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA. Under this agreement, the transmission owners, which also include Southern California Edison, or SCE, San Diego Gas & Electric Company and several municipal utilities, assign operational control of their electricity transmission systems to the ISO. In addition, as a party to the TCA, the Utility is responsible for a share of the costs of reliability must-run, or RMR, agreements between the ISO and owners of the power plants subject to RMR agreements, or RMR Plants. The Utility also is an owner of some of these RMR Plants for which the Utility receives revenue from the ISO. Under the RMR agreements, RMR Plants must remain available to generate electricity when needed for local transmission system reliability upon the ISO’s demand.

NEGT and its creditors have filed a complaint against PG&E Corporation and two PG&E Corporation officers who previously served on NEGT’s Board of Directors, in NEGT’s Chapter 11 proceeding, asserting, among other claims, that NEGT is entitled to be compensated under an alleged tax sharing agreement between PG&E Corporation and NEGT for any tax savings achieved by PG&E Corporation as a result of the incorporation of the losses and deductions related to NEGT or its subsidiaries in PG&E Corporation’s consolidated federal income tax return. In May 2003, PG&E Corporation received a return of $533 million from the IRS for an overpayment of 2002 estimated federal income taxes. In November 2003, NEGT and its creditors amended their complaint to add additional causes of action arising out of or related to the filing by PG&E Corporation of its 2002 federal consolidated tax return, and certain restructuring negotiations that occurred between PG&E Corporation and certain creditors of NEGT’s prior to NEGT’s Chapter 11 filing, including claims for breach of contract, breach of fiduciary duty, violation of the automatic stay, turnover, an accounting, unjust enrichment, fraudulent transfer, constructive trust, breach of standstill agreement, deceit equitable subordination and indemnification. NEGT and the creditors’ committees seek a declaration that an

implied tax sharing agreement exists between PG&E Corporation and NEGT as well as injunctive relief prohibiting PG&E Corporation from taking certain tax positions on its consolidated tax returns in the future. The complaint also alleges a cause of action for breach of fiduciary duty against two PG&E Corporation officers who previously served on NEGT’s Board of Directors. NEGT and its creditors recently agreed to dismiss the equitable subordination and indemnification claims without prejudice.

NEGT and its creditors have asserted that they have a direct interest in certain tax savings achieved by PG&E Corporation and are entitled to be paid approximately $414 million of the funds received by PG&E Corporation (approximately $361.5 million achieved by the incorporation of losses and deductions related to NEGT or its subsidiaries and approximately $53 million achieved by the incorporation of certain tax credits related to one of NEGT’s subsidiaries). In addition to at least $414 million in damages, the plaintiffs seek punitive damages against PG&E Corporation for deceit, as well as interest, costs of suit, and reasonable attorney’s fees.

Defendants have filed a motion in the U.S. District Court of Maryland seeking to transfer the litigation from the bankruptcy court to the District Court. The District Court has scheduled a hearing date of April 22, 2004 for this motion.

Defendants also have filed a motion in the bankruptcy court to dismiss the complaint while awaiting a decision from the District Court. A hearing on this motion has been set for March 25, 2004. In the meantime, the bankruptcy court has set a trial date for January 2005.

PG&E Corporation denies that any tax sharing agreement, whether implied or expressed, ever existed and denies that it has any obligation to compensate NEGT for the incorporation of losses, deductions and tax credits related to NEGT or its subsidiaries into PG&E Corporation’s consolidated federal tax returns, as required under the Internal Revenue Code. Until the dispute is resolved, PG&E Corporation is treating $361.5 million as restricted cash included in noncurrent other assets on PG&E Corporation’s Consolidated Balance Sheet at December 31, 2003. PG&E Corporation anticipates continuing to incorporate losses, deductions and certain tax credits related to NEGT or its subsidiaries in PG&E Corporation’s consolidated income tax return, until it is no longer consolidated for federal income tax purposes. NEGT and its creditors have asserted that NEGT should be compensated for any such tax savings.

PG&E Corporation does not expect that the outcome of this matter will have a material adverse effect on its results of operations, financial position or liquidity.

As further disclosed below, PG&E Corporation has guaranteed the Utility’s reimbursement obligation associated with certain surety bonds and the Utility’s obligation to pay workers’ compensation claims.

In July 2003, the Utility and various intervenors (The CPUC’s Office of Ratepayer Advocates, or ORA, TURN, Aglet Consumer Alliance, and the City and County of San Francisco) filed a joint motion with the CPUC seeking approval of a settlement agreement resolving specific issues related to the cost of operating the Utility’s electricity generation facilities, or the generation settlement. In September 2003, the Utility and various intervenors (ORA, TURN, Aglet Consumer Alliance, the Modesto Irrigation District, the Natural Resources Defense Council and the Agricultural Energy Consumers Association) filed a joint motion with the CPUC seeking approval of the GRC settlement. The GRC settlement, together with the generation settlement, resolves all disputed economic issues among the settling parties related to the Utility’s electricity distribution, natural gas distribution, and generation revenue requirements, with the exception of the Utility’s request that the CPUC include the costs of a pension contribution in the Utility’s revenue requirement. The CPUC will resolve the pension contribution issue, as well as other issues raised by non-settling intervenors, in its final decision. The CPUC agreed in the Settlement Agreement to act promptly on the 2003 GRC.

The GRC settlement would result in a total 2003 revenue requirement of approximately $2.5 billion for electricity distribution operations, representing a $236 million increase in the Utility’s electricity distribution revenue

requirement over the current authorized amount. The GRC settlement provides that the electricity distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be approximately $7.7 billion, based on recorded 2002 plant, and including net weighted average capital additions for 2003 of approximately $292 million.

The GRC settlement also would result in a total 2003 revenue requirement of approximately $927 million for the Utility’s natural gas distribution operations, representing a approximately $52 million increase in the Utility’s natural gas distribution revenue requirement over the current authorized amount. The GRC settlement also provides that the amount of natural gas distribution rate base on which the Utility would be entitled to earn an authorized rate of return would be approximately $2.1 billion, based on recorded 2002 plant, and including weighted average capital additions for 2003 of approximately $89 million.

Together with the generation settlement, the GRC settlement would result in a 2003 generation revenue requirement of approximately $912 million representing an increase of approximately $38 million in the Utility’s generation revenue requirement over the current authorized amount. This generation revenue requirement excludes fuel expense, the cost of electricity purchases, the DWR revenue requirements and nuclear decommissioning revenue requirements. Under the Settlement Agreement, the Utility’s adopted 2003 generation rate base of approximately $1.6 billion would be deemed just and reasonable by the CPUC and not subject to modification, adjustment or reduction, except as necessary to reflect capital expenditures and changes in authorized depreciation. This reaffirmation of the Utility’s electricity generation rate base would allow recognition of an after-tax regulatory asset of approximately $800 million (or approximately $1.3 billion pre-tax) as estimated at December 31, 2003. The Utility expects to record this regulatory asset when it meets the probability requirements for regulatory recovery in rates as provided for in SFAS No. 71. The individual components of the regulatory asset will be amortized over their respective lives. The weighted average life of these individual components is approximately 16 years.

The GRC settlement also provides for new balancing accounts to be established retroactive to January 1, 2004, that permit the Utility to recover its authorized electricity distribution and generation revenue requirements regardless of the level of sales. If sales levels do not generate revenues equal to the full revenue requirement in a period, rates in subsequent periods will be increased to collect the shortfall. Similarly, future rates will decrease if sales levels generate more than the full revenue requirement.

On February 3, 2004, the CPUC reopened the 2003 GRC record for the purpose of taking further evidence regarding executive compensation and bonuses. The Utility has filed a report addressing these issues with the CPUC. PG&E Corporation and the Utility are uncertain how this matter will be resolved and when a final GRC decision will be issued.

In January 2001, the CPUC authorized increases in electricity rates of $0.01 per kilowatt-hour, or kWh, in March 2001 of another $0.03 per kWh and in May 2001 of an additional $0.005 per kWh. The use of these surcharge revenues was restricted to “ongoing procurement costs” and “future power purchases.” In November and December 2002, the CPUC approved decisions modifying the restrictions on the use of revenues generated by the surcharges and authorizing the surcharges to be used to restore the Utility’s financial health by permitting the Utility to record amounts related to the surcharge revenues as an offset to unrecovered transition costs. From January 2001 to December 31, 2003, the Utility recognized total surcharge revenues subject to refund of approximately $8.1 billion, pre-tax. The rate design settlement includes a refund of approximately $125 million of surcharge revenues. Accordingly, at December 31, 2003, the Utility had recorded a regulatory liability for potential refund of approximately $125 million of surcharge revenues collected in 2003. In addition, if the CPUC requires the Utility to refund any amounts in excess of $125 million, the Utility’s earnings could be materially adversely affected.

The Utility had PX block-forward contracts, which were seized by California then-Governor Gray Davis in February 2001 for the benefit of the state, acting under California’s Emergency Services Act. The block-forward contracts had an estimated unrealized gain of up to $243 million at the time the state of California seized them. The Utility, the PX, and some of the PX market participants have filed claims in state court against the state of California to recover the value of the seized contracts; the state of California disputes the plaintiff’s valuations. This state court litigation is pending.

During 2003, the FERC confirmed most of the administrative law judge’s findings, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX, which operates solely to reconcile remaining refund amounts owed, to make compliance filings establishing refund amounts by March 2004. The ISO has indicated that it plans to make its compliance filing by August 2004. The actual refunds will not be determined until the FERC issues a final decision, following the ISO and PX compliance filings. The FERC is uncertain when it will issue a final decision in this proceeding. In addition, future refunds could increase or decrease as a result of an alternative calculation proposed by the ISO, which incorporates revised data provided by the Utility and other entities.

The Utility has recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. The Utility currently estimates that the claims filed would have been reduced to approximately $1.2 billion based on the refund methodology recommended in the administrative law judge’s initial decision, resulting in a net liability of approximately $1.0 billion after the approximately $200 million pre-petition offset. The recalculation of market prices according to the revised methodology adopted by the FERC in its October 2003 decision could further reduce the amount of the suppliers’ claims by several hundred million dollars. However this reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology.

The Utility has several types of nuclear insurance for its Diablo Canyon power plant and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay additional annual premiums of up to $36.7 million.

NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.9 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.9 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of reactors 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to $100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $20 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including the Diablo Canyon power plant, that had coverage before December 31, 2003. Congress may address renewal of the Price-Anderson Act in future energy legislation.

In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at Humboldt Bay power plant and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

The Utility is self-insured for workers’ compensation. The Utility must deposit collateral with the California Department of Industrial Relations, or DIR, to maintain its status as a self-insurer for workers’ compensation claims made against the Utility. Acceptable forms of collateral include surety bonds, letters of credit, cash and securities. At December 31, 2003, the Utility provided collateral in the form of $305 million in surety bonds and approximately $43 million in a cash deposit.

In February 2001, several surety companies provided cancellation notices because of the Utility’s financial situation. The cancellation of these bonds has not impacted the Utility’s self-insured status under California law. The DIR has not agreed to release the canceling sureties from their obligations for claims occurring before the cancellation and has continued to apply the canceled bond amounts, totaling $185 million, toward the $348 million collateral requirement. At December 31, 2003, the Utility’s $348 million in collateral consisted of the $185 million in cancelled bonds, $120 million in active surety bonds and approximately $43 million in cash. PG&E Corporation has guaranteed the Utility’s reimbursement obligation associated with these surety bonds and the Utility’s underlying obligation to pay workers’ compensation claims.

2003, the CPUC approved an allocation of these refunds, under which the Utility’s natural gas customers would receive approximately $80 million and its electricity customers would receive approximately $216 million. The settlement was approved by the FERC in November 2003 and by the San Diego Superior Court in December 2003. At least one appeal of the San Diego Superior Court’s approval has been filed; however, the Utility believes that it is probable that the El Paso settlement will not be overturned on appeal.

The DWR provided approximately 30% of the electricity delivered to the Utility’s customers for the year ended December 31, 2003. The DWR purchased the electricity under contracts with various generators and through open market purchases. The Utility is responsible for administration and dispatch of the DWR’s electricity procurement contracts allocated to the Utility, for purposes of meeting a portion of the Utility’s net open position. The DWR remains legally and financially responsible for the electricity procurement contracts.

The contracts terminate at various times through 2012, and consist of must-take and capacity charge contracts. Under must-take contracts, the DWR must take and pay for electricity generated by the applicable generating facility regardless of whether the electricity is needed. Under capacity charge contracts, the DWR must pay a capacity charge but is not required to purchase electricity unless that electricity is dispatched and delivered.


	•	After assumption, the Utility’s issuer rating by Moody’s will be no less than A2 and the Utility’s long-term issuer credit rating by S&P will be no less than A;

	•	The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

	•	The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

The Utility may be required to pay for environmental remediation at sites where it has been, or may be, a potentially responsible party under the Comprehensive Environmental Response Compensation and Liability Act of 1980, or CERCLA, as amended, and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, and sites used by the Utility for the storage, recycling or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if the Utility did not deposit those substances on the site.

The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of reasonably likely clean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where it may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at

similar sites and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility records the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility’s responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

The Utility had an undiscounted environmental remediation liability of approximately $314 million at December 31, 2003 and approximately $331 million at December 31, 2002. During 2003, the liability was reduced by approximately $17 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $314 million accrued at December 31, 2003 includes approximately $104 million related to the pre-closing remediation liability associated with divested generation facilities and approximately $210 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third party disposal sites and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $314 million environmental remediation liability, approximately $147 million has been included in prior rate setting proceedings and the Utility expects that approximately $116 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility’s ultimate obligations may be subject to refund to ratepayers.

The Utility’s undiscounted future costs could increase to as much as $422 million if the other potentially responsible parties are not financially able to contribute to these costs, or the extent of contamination or necessary remediation is greater than anticipated. The approximately $422 million amount does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility’s predecessor corporations for which the Utility has not been able to determine whether liability exists.

The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility’s Chapter 11 proceeding for environmental remediation at numerous sites totaling approximately $770 million. For most of these sites, remediation is ongoing in the ordinary course of business or the Utility is in the process of remediation in cooperation with the relevant agencies and other parties responsible for contributing to the clean-up. Other sites identified in the California Attorney General’s claims may not, in fact, require remediation or clean-up actions. The Utility’s Plan of Reorganization provides that the Utility intends to respond to these types of claims in the ordinary course of business, and since the Utility has not argued that the Chapter 11 proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the California Attorney General’s claims seeking specific cash recoveries are unenforceable. Environmental claims in the ordinary course of business will not be discharged in the Utility’s Chapter 11 proceeding and will pass through the Chapter 11 proceeding unimpaired.

In the normal course of business, PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. The most significant of these are discussed below. The Utility’s Chapter 11 filing on April 6, 2001, discussed in Note 2, automatically stayed the litigation described below against the Utility, except as otherwise noted.

There are 14 civil suits pending against the Utility in several California state courts. One of these suits also names PG&E Corporation as a defendant. Currently, there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed proofs of claims with the bankruptcy court, most of whom are plaintiffs in the 14 chromium litigation cases. Approximately 1,035 of these claimants have filed proofs of claim requesting an approximate aggregate amount of $580 million and approximately another 225 claimants have filed claims for an “unknown amount.”

In general, plaintiffs and claimants allege that exposure to chromium at or near the Utility’s compressor stations at Hinkley and Kettleman, California, and the area of California near Topock, Arizona, caused personal injuries, wrongful death, or other injury and seek related damages. The bankruptcy court has granted certain claimants’ motion for relief from stay so that the state court lawsuits pending before the Utility’s Chapter 11 filing can proceed.

The Utility is responding to the suits in which it has been served and is asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including statute of limitations, exclusivity of workers’ compensation

To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from three of the cases for a test trial. Plaintiffs’ counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the initial trial plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 13 summary judgment motions or motions in limine, which are motions to exclude potentially prejudicial information, challenging the claims of the trial test plaintiffs. Two of the 13 summary judgment motions are scheduled for hearing in February 2004. The trial of the test cases is scheduled to begin in March 2004. The Utility also has filed a motion to dismiss the complaint in one of the cases. After a hearing in November 2003, the motion to dismiss was granted. The plaintiffs in that case have until March 2004 to file an amended complaint.

The Utility has recorded a $160 million reserve in its financial statements for these matters. PG&E Corporation and the Utility believe that, after taking into account the reserves recorded at December 31, 2003, the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation’s or the Utility’s financial condition or future results of operations.

In accordance with SFAS No. 5, “Accounting for Contingencies,” PG&E Corporation and the Utility make a provision for a liability when it is both probable that a liability has been incurred and the amount of the loss can be reasonably estimated. These provisions are reviewed quarterly and adjusted to reflect the impacts of negotiations, settlements and payments, rulings, advice of legal counsel and other information and events pertaining to a particular case.

The provision for legal matters is included in PG&E Corporation’s and the Utility’s other noncurrent liabilities in the Consolidated Balance Sheets, and totaled approximately $205 million at December 31, 2003 and $202 million at December 31, 2002.


⁽¹⁾	The operating results of NEGT have been excluded from continuing operations and reported as discontinued operations for all periods. (See Note 5 of the Notes to the Consolidated Financial Statements). Operating revenues, operating income (loss) and income (loss) from continuing operations previously reported for quarter ended March 31, 2003 were $2,401 million, $(129) million and $(278) million; $2,926 million, $703 million and $219 million for the quarter ended June 30, 2003; and $3,103 million, $1,173 million and $508 million for the quarter ended September 30, 2003. Operating revenues, operating income (loss) and income (loss) from continuing operations previously reported for the quarters ended March 31, 2002 were $2,935 million, $1,301 million and $623 million; $2,937 million, $783 million and $279 million for the quarter ended June 30, 2002; $2,947 million, $1,069 million and $479 million for the quarter ended September 30, 2002; and $2,968 million, $(1,949) million and $(1,417) million for the quarter ended December 31, 2002.

⁽²⁾	Operating revenues for the quarter ended December 31, 2003, include the recognition of a regulatory liability of approximately $125 million for surcharge revenues collected during 2003.

⁽³⁾	Operating income, income from continuing operations, and net income for the quarter ended March 31, 2002 includes a $970 million non-cash reduction to the costs of electricity related to a reversal of ISO charges.

⁽⁴⁾	Net loss for the quarter ended March 31, 2003 includes $200 million of impairments, write-offs and charges recognized by NEGT. These impairments have been excluded from continuing operations and are reported as discontinued operations.

⁽⁵⁾	Net income for the quarter ended December 31, 2002 includes $2.4 billion of impairments, write-offs and charges recognized by NEGT. These impairments have been excluded from continuing operations and are reported as discontinued operations.

We have audited the accompanying consolidated balance sheets of PG&E Corporation and subsidiaries (the “Company”) and of Pacific Gas and Electric Company (a Debtor-in-Possession) and subsidiaries (the “Utility”) as of December 31, 2003 and 2002, and the related consolidated statements of operations, cash flows and shareholders’ equity of the Company and the related consolidated statements of operations, cash flows and shareholders’ equity of the Utility for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the respective managements of the Company and of the Utility. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the respective consolidated financial position of the Company and of the Utility as of December 31, 2003 and 2002, and the respective results of their consolidated operations and cash flows for each of the three years in the period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 of the Notes to the Consolidated Financial Statements, during 2003, the Company and the Utility adopted new accounting standards to account for asset retirement obligations and financial instruments with characteristics of both liabilities and equity. Additionally, as described in Note 5 to the Notes to the Consolidated Financial Statements, during 2003, the Company changed the method of reporting hedge transactions. During 2002, the Company adopted new accounting standards to account for goodwill and intangible assets, impairment of long-lived assets, discontinued operations, gains and losses on debt extinguishment and certain derivative contracts. During 2001, the Company and the Utility adopted new accounting standards related to derivatives and certain interpretations of the Derivatives Implementation Group of the Financial Accounting Standards Board.

As discussed in Note 5 of the Notes to the Consolidated Financial Statements, revenues and expenses of discontinued operations for the years ended December 31, 2002 and 2001 have been revised.

The accompanying consolidated financial statements have been prepared on a going concern basis of accounting. As discussed in Notes 1 and 2 of the Notes to the Consolidated Financial Statements, the Utility, a subsidiary of the Company, has incurred power purchase costs substantially in excess of amounts charged to customers in rates. On April 6, 2001, the Utility sought protection from its creditors by filing a voluntary petition under provisions of Chapter 11 of the U.S. Bankruptcy Code. These matters raise substantial doubt about the ability of the Company and of the Utility to continue as going concerns. Managements’ plans in regard to these matters are also described in Note 2 of the Notes to the Consolidated Financial Statements. The respective consolidated financial statements do not include any adjustments that might result from the outcome of these uncertainties.

PG&E Corporation and Pacific Gas and Electric Company, or the Utility, management are responsible for the integrity of the accompanying Consolidated Financial Statements. The financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America. Management considers materiality and uses its best judgment to ensure that such statements reflect fairly the financial position, results of operations, and cash flows of PG&E Corporation and the Utility.

PG&E Corporation and the Utility maintain systems of internal controls supported by formal policies and procedures, which are communicated throughout PG&E Corporation and the Utility. These controls are adequate to provide reasonable assurance that assets are safeguarded from material loss or unauthorized use and that necessary records are produced for the preparation of consolidated financial statements. There are limits inherent in all systems of internal controls, based on recognition that the costs of such systems should not exceed the benefits to be derived. PG&E Corporation and the Utility believe that their systems of internal control provide this appropriate balance. PG&E Corporation management also maintains a staff of internal auditors who evaluate the adequacy of, and assess the adherence to, these controls, policies, and procedures for all of PG&E Corporation, including the Utility.

Both PG&E Corporation’s and the Utility’s Consolidated Financial Statements included herein have been audited by Deloitte & Touche LLP, PG&E Corporation’s independent auditors. The audit includes consideration of internal accounting controls and performance of tests necessary to support an opinion. The auditors’ report contains an independent informed judgment as to the fairness, in all material respects, of reported results of operations and financial position.

The Audit Committee of the Board of Directors of PG&E Corporation meets regularly with management, internal auditors, and Deloitte & Touche LLP, jointly and separately, to review internal accounting controls and auditing and financial reporting matters. The internal auditors and Deloitte & Touche LLP have free access to the Audit Committee, which consists of five outside directors. The Audit Committee has reviewed the financial data contained in this report.

PG&E Corporation and the Utility are committed to full compliance with all laws and regulations and to conducting business in accordance with high standards of ethical conduct. Management has taken the steps necessary to ensure that all employees and other agents understand and support this commitment. Guidance for corporate compliance and ethics is provided by an officers’ Ethics Committee and by a Legal Compliance and Business Ethics organization. PG&E Corporation and the Utility believe that these efforts provide reasonable assurance that each of their operations is conducted in conformity with applicable laws and with their commitment to ethical conduct.


	2003		2002		2001		2000			1999
(in millions, except per share amounts)
PG&E Corporation ⁽¹⁾
For the Year
Operating revenues	$	10,435	$	10,505	$	10,450	$	9,623		$	9,084
Operating income (loss)		2,343		3,954		2,613		(5,077	)		1,950
Income (loss) from continuing operations		791		1,723		1,021		(3,435	)		713
Earnings (loss) per common share from continuing operations, basic		2.05		4.64		2.81		(9.49	)		1.94
Earnings (loss) per common share from continuing operations, diluted		1.96		4.50		2.80		(9.49	)		1.93
Dividends declared per common share		–		–		–		1.20			1.20
At Year-End
Book value per common share	$	10.75	$	9.47	$	11.91	$	8.76		$	19.13
Common stock price per share		27.77		13.90		19.24		20.00			20.50
Total assets		30,175		33,060		35,693		36,152			29,588
Long-term debt (excluding current portion)		3,314		3,715		3,923		3,346			4,877
Rate reduction bonds (excluding current portion)		870		1,160		1,450		1,740			2,031
Financial debt subject to compromise		5,603		5,605		5,651		–			–
Redeemable preferred stock and securities of subsidiaries (excluding current portion)		286		286		586		586			586
Pacific Gas and Electric Company ⁽¹⁾
For the Year
Operating revenues	$	10,438	$	10,514	$	10,462	$	9,637		$	9,228
Operating income (loss)		2,339		3,913		2,478		(5,201	)		1,993
Income available for (loss allocated to) common stock		901		1,794		990		(3,508	)		763
At Year-End
Total assets	$	29,066	$	24,572	$	25,269	$	21,988		$	21,470
Long-term debt (excluding current portion)		2,431		2,739		3,019		3,342			4,877
Rate reduction bonds (excluding current portion)		870		1,160		1,450		1,740			2,031
Financial debt subject to compromise		5,603		5,605		5,651		–			–
Redeemable preferred stock and securities (excluding current portion)		286		286		586		586			586


		Amount Owed
(in millions)
Revolving line of credit		$	938
Bank borrowing — letters of credit for accelerated pollution control loan agreements			454
Floating rate notes			1,240
Commercial paper			873
Senior notes			680
Pollution control loan agreements			814
Medium-term notes			287
Deferrable interest subordinated debentures			300
Other long-term debt			17

	Financing debt subject to compromise		5,603
Trade creditors subject to compromise			3,899
Mortgage bonds			2,741
Interest and dividends			20

	Total	$	12,263


	2003			2002			2001
(in millions)
Utility
Electric operating revenue	$	7,582		$	8,178		$	7,326
Natural gas operating revenue		2,856			2,336			3,136
Cost of electricity		2,319			1,482			2,774
Cost of natural gas		1,467			954			1,832
Operating and maintenance		2,935			2,817			2,385
Depreciation, amortization and decommissioning		1,218			1,193			896
Reorganization professional fees and expenses		160			155			97

Operating income		2,339			3,913			2,478
Interest income		53			74			123
Interest expense		(953	)		(988	)		(974	)
Other expense, net ⁽¹⁾		(9	)		(27	)		(41	)

Income before income taxes		1,430			2,972			1,586
Income tax provision		528			1,178			596

Income before cumulative effect of a change in accounting principle		902			1,794			990
Cumulative effect of a change in accounting principle		(1	)		–			–

Income available for common stock	$	901		$	1,794		$	990

PG&E Corporation, Eliminations and Other ⁽²⁾⁽³⁾
Operating revenues	$	(3	)	$	(9	)	$	(12	)
Operating expenses		(7	)		(50	)		(147	)

Operating income		4			41			135
Interest income		9			6			14
Interest expense		(194	)		(236	)		(104	)
Other income (expense), net ⁽¹⁾		–			77			(2	)

Income (loss) before income taxes		(181	)		(112	)		43
Income tax provision (benefit)		(70	)		(41	)		12

Income (loss) from continuing operations		(111	)		(71	)		31
Discontinued operations		(365	)		(2,536	)		69
Cumulative effect of changes in accounting principles		(5	)		(61	)		9

Net income (loss)	$	(481	)	$	(2,668	)	$	109

Consolidated Total ⁽³⁾
Operating revenues	$	10,435		$	10,505		$	10,450
Operating expenses		8,092			6,551			7,837

Operating income		2,343			3,954			2,613
Interest income		62			80			137
Interest expense		(1,147	)		(1,224	)		(1,078	)
Other income (expense), net ⁽¹⁾		(9	)		50			(43	)

Income before income taxes		1,249			2,860			1,629
Income tax provision		458			1,137			608

Income from continuing operations		791			1,723			1,021
Discontinued operations		(365	)		(2,536	)		69
Cumulative effect of changes in accounting principles		(6	)		(61	)		9

Net income (loss)	$	420		$	(874	)	$	1,099


		2003			2002			2001
(in millions)
Residential		$	3,671		$	3,646		$	3,396
Commercial			4,440			4,588			4,105
Industrial			1,410			1,449			1,554
Agricultural			522			520			525
Miscellaneous			59			316			380
Direct access credits			(277	)		(285	)		(461	)
DWR pass-through revenue			(2,243	)		(2,056	)		(2,173	)

	Total electric operating revenues	$	7,582		$	8,178		$	7,326


		2003			2002			2001
(in millions)
Cost of purchased power		$	2,449		$	1,980		$	3,224
Proceeds from surplus sales allocated to the Utility			(247	)		–			–
Fuel used in own generation			117			97			102
Adjustments to purchased power accruals			–			(595	)		(552	)

	Total net cost of electricity	$	2,319		$	1,482		$	2,774

Average cost of purchased power per kWh		$	0.076		$	0.081		$	0.143

Total purchased power (GWh)			32,249			24,552			22,592



			Payment due by period

					Less than						More than
			Total		one year		1-3 years		3-5 years		5 years

Utility off balance sheet commitments:
Power purchase agreements ⁽¹⁾:
	Qualifying facilities		$	19,960	$	1,590	$	3,090	$	2,880	$	12,400
	Irrigation district and water agencies			624		69		118		113		324
	Other power purchase agreements			435		96		126		85		128
Natural gas supply and transportation				1,000		852		141		7		–
Nuclear fuel				194		90		25		27		52
Other commitments ⁽²⁾				238		126		78		29		5
Employee benefits:
	Pension ⁽³⁾			386		129		257		–		–
	Postretirement benefits other than pension ⁽³⁾			194		65		129		–		–

Total Utility off balance sheet commitments				23,031		3,017		3,964		3,141		12,909
Long-term debt:
	Liabilities not subject to compromise:
		Fixed rate principal obligations		2,741		310		289		–		2,142
	Liabilities subject to compromise:
		Fixed rate principal obligations		1,184		225		697		1		261
		7.90% Deferrable Interest Subordinated Debentures		300		–		–		–		300
		Variable rate principal obligations		614		349		265		–		–
Rate reduction bonds				1,160		290		580		290		–
Preferred dividends and redemption requirements ⁽⁴⁾				198		41		31		79		47
PG&E Corporation:
Long-term debt:
	6 7/8% Senior Secured Notes			600		–		–		600		–
	Convertible Subordinated Notes			280		–		–		–		280
	Other long-term debt			3		–		–		3		–
Operating leases				9		4		3		2		–


(in millions)
2004		$	126
2005			48
2006			30
2007			15
2008			14
Thereafter			5

	Total	$	238


(in millions)
2004	$	1,695
2005		1,806
2006		1,569
2007		1,659
2008		1,716


	2004	2005	2006

Minimum	2.00% Distribution	2.25% Distribution	3.00% Distribution
	1.50% Generation	1.50% Generation	2.50% Generation
Multiplier	Change in CPI	Change in CPI	Change in CPI + 1%
Maximum	3.00% Distribution	3.25% Distribution	4.00% Distribution
	3.00% Generation	3.00% Generation	4.00% Generation



			Year ended December 31,

			2003			2002			2001

Operating Revenues
	Electric		$	7,582		$	8,178		$	7,326
	Natural gas			2,853			2,327			3,124

		Total operating revenues		10,435			10,505			10,450

Operating Expenses
	Cost of electricity			2,309			1,447			2,717
	Cost of natural gas			1,438			895			1,720
	Operating and maintenance			2,963			2,858			2,404
	Depreciation, amortization, and decommissioning			1,222			1,196			899
	Reorganization professional fees and expenses			160			155			97

		Total operating expenses		8,092			6,551			7,837

Operating Income (Loss)				2,343			3,954			2,613
	Reorganization interest income			46			71			91
	Interest income			16			9			46
	Interest expense			(1,147	)		(1,224	)		(1,078	)
	Other income (expense), net			(9	)		50			(43	)

Income Before Income Taxes				1,249			2,860			1,629
	Income tax provision			458			1,137			608

Income From Continuing Operations				791			1,723			1,021
Discontinued Operations
	Earnings (Loss) from operations of NEGT (net of income tax benefit of $230 million in 2003, $1,558 million in 2002, and none in 2001)			(365	)		(2,536	)		69

Net Income (Loss) Before Cumulative Effect of Changes in Accounting Principles				426			(813	)		1,090
	Cumulative effect of changes in accounting principles of $(5) million in 2003, $(61) million in 2002, and $9 million in 2001 related to discontinued operations (net of income tax expense (benefit) of $(3) million in 2003, $(42) million in 2002, and $6 million in 2001). In 2003, $(1) million related to continuing operations (net of income tax benefit of $1 million)			(6	)		(61	)		9

Net Income (Loss)			$	420		$	(874	)	$	1,099

Weighted Average Common Shares Outstanding, Basic				385			371			363

Earnings Per Common Share from Continuing Operations, Basic			$	2.05		$	4.64		$	2.81

Net Earnings (Loss) Per Common Share, Basic			$	1.09		$	(2.36	)	$	3.03

Earnings Per Common Share from Continuing Operations, Diluted			$	1.96		$	4.50		$	2.80

Net Earnings (Loss) Per Common Share, Diluted			$	1.06		$	(2.26	)	$	3.02



			Balance at
			December 31,

			2003			2002

ASSETS
Current Assets
	Cash and cash equivalents		$	3,658		$	3,532
	Restricted cash			403			527
	Accounts receivable:
		Customers (net of allowance for doubtful accounts of $68 million in 2003 and $59 million in 2002)		2,424			1,921
		Related parties		15			–
		Regulatory balancing accounts		248			98
	Inventories:
		Gas stored underground		166			154
		Materials and supplies		126			121
	Current assets of NEGT			–			3,029
	Prepaid expenses and other			108			111

		Total current assets		7,148			9,493

Property, Plant and Equipment
	Electric			20,468			18,922
	Gas			8,355			8,123
	Construction work in progress			379			427
	Other			20			21

		Total property, plant and equipment		29,222			27,493
	Accumulated depreciation			(11,115	)		(13,528	)

		Net property, plant and equipment		18,107			13,965

Other Noncurrent Assets
	Regulatory assets			2,001			2,011
	Nuclear decommissioning funds			1,478			1,335
	Long-term assets of NEGT			–			4,883
	Other			1,441			1,373

		Total other noncurrent assets		4,920			9,602

TOTAL ASSETS			$	30,175		$	33,060


																Accumulated
																other			Total
							Common						Reinvested			compre-			common
							stock						earnings			hensive			share-			Comprehensive
	Common stock			Common			held by			Unearned			(accumulated			income			holders’			income
	shares			stock			subsidiary			compensation			deficit)			(loss)			equity			(loss)

Balance at December 31, 2000		387,193,727		$	5,971		$	(690	)		–		$	(2,105	)	$	(4	)	$	3,172
Net income					–			–			–			1,099			–			1,099		$	1,099
Cumulative effect of adoption of SFAS No. 133 and interpretations (net of income tax benefit of $86 million)					–			–			–			–			(243	)		(243	)		(243	)
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax expense of $105 million)					–			–			–			–			237			237			237
Net reclassification to earnings (net of income tax benefit of $2 million)					–			–			–			–			42			42			42
Foreign currency translation adjustment (net of income tax benefit of $1 million)					–			–			–			–			(1	)		(1	)		(1	)
Other (net of zero income tax)					–			–			–			–			(1	)		(1	)		(1	)

Comprehensive income											–											$	1,133

Common stock issued		739,158			16			–			–			–			–			16
Common stock repurchased		(34,037	)		(1	)		–			–			–			–			(1	)
Other					–			–			–			2			–			2

Balance at December 31, 2001		387,898,848			5,986			(690	)		–			(1,004	)		30			4,322
Net loss					–			–			–			(874	)		–			(874	)	$	(874	)
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax benefit of $44 million)					–			–			–			–			(139	)		(139	)		(139	)
Net reclassification to earnings (net of income tax expense of $4 million)					–			–			–			–			13			13			13
Foreign currency translation adjustment (net of income tax expense of $1 million)					–			–			–			–			2			2			2
Other (net of zero income tax)					–			–			–			–			1			1			1

Comprehensive income											–											$	(997	)

Common stock issued		17,582,636			217			–			–			–			–			217
Common stock repurchased		(6,580	)		–			–			–			–			–			–
Warrants issued		–			71			–			–			–			–			71
Common stock warrants exercised		11,111			–			–			–			–			–			–

Balance at December 31, 2002		405,486,015			6,274			(690	)		–			(1,878	)		(93	)		3,613
Net income		–			–			–			–			420			–			420		$	420
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax benefit of $10 million)		–			–			–			–			–			(8	)		(8	)		(8	)
Retirement plan remeasurement (net of income tax benefit of $3 million)		–			–			–			–			–			(4	)		(4	)		(4	)
Net reclassification to earnings (net of income tax expense of $27 million)		–			–			–			–			–			17			17			17
Foreign currency translation adjustment (net of income tax expense of $5 million)		–			–			–			–			–			3			3			3

Comprehensive income		–			–			–			–			–			–			–		$	428

Common stock issued		8,796,632			166			–			–			–			–			166
Common stock warrants exercised		702,367			–			–			–			–			–			–
Common restricted stock issued		1,590,010			28			–			(28	)		–			–			–
Common restricted stock cancelled		(54,742	)		(1	)		–			1			–			–			–
Common restricted stock amortization		–			–			–			7			–			–			7
Other		–			1			–			–			–			–			1

Balance at December 31, 2003		416,520,282		$	6,468		$	(690	)	$	(20	)	$	(1,458	)	$	(85	)	$	4,215


											Accumu-
											lated						Preferred
								Reinvested			Other			Total			Stock
					Common			Earnings			Compre-			Common			Without
			Additional		Stock Held			(Accumu-			hensive			Share-			Mandatory		Comprehensive
	Common		Paid-in		by			lated			Income			holders’			Redemption		Income
	Stock		Capital		Subsidiary			Deficit)			(Loss)			Equity			Provisions		(Loss)
(in millions, except share amounts)
Balance December 31, 2000	$	1,606	$	1,964	$	(475	)	$	(1,979	)	$	–		$	1,116		$	294
Net Income		–		–		–			1,015			–			1,015			–	$	1,015
Cumulative effect of adoption of SFAS No. 133 (net of income tax expense of $62 million)		–		–		–			–			90			90			–		90
Mark-to-market adjustments for hedging (net of income tax benefit of $3 million)		–		–		–			–			(5	)		(5	)		–		(5	)
Net reclassification to earnings (net of income tax benefit of $58 million)		–		–		–			–			(85	)		(85	)		–		(85	)
Foreign currency translation adjustments (net of income tax benefit of $1 million)		–		–		–			–			(2	)		(2	)		–		(2	)

Comprehensive income																			$	1,013

Preferred stock dividend requirement		–		–		–			(25	)		–			(25	)		–

Balance December 31, 2001		1,606		1,964		(475	)		(989	)		(2	)		2,104			294
Net Income		–		–		–			1,819			–			1,819			–	$	1,819
Foreign currency translation adjustments (net of income tax expense of $1 million)		–		–		–			–			2			2			–		2

Comprehensive income																			$	1,821

Preferred stock dividend requirement		–		–		–			(25	)		–			(25	)		–

Balance December 31, 2002		1,606		1,964		(475	)		805			–			3,900			294
Net Income		–		–		–			923			–			923			–	$	923
Retirement plan remeasurement (net of income tax benefit of $2 million)		–		–		–			–			(3	)		(3	)		–		(3	)
Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133 (net of income tax benefit of $2 million)		–		–		–			–			(3	)		(3	)		–		(3	)

Comprehensive income																			$	917

Preferred stock dividend requirement		–		–		–			(22	)		–			(22	)		–

Balance December 31, 2003	$	1,606	$	1,964	$	(475	)	$	1,706		$	(6	)	$	4,795		$	294



							Receivable
							(Payable)
							Balance
							Outstanding at
	Year Ended						Year Ended
	December 31,						December 31,

	2003		2002		2001		2003		2002
(in millions)
Utility revenues from:
Administrative services provided to PG&E Corporation	$	8	$	7	$	6	$	–	$	1
Natural gas transportation capacity services provided to NEGT ET		8		9		11		–		–
Contribution in aid of construction received from NEGT		–		2		5		–		3
Trade deposit due from GTNW		3		–		11		15		12
Other		–		–		1		–		–


		Gross Plant (in millions)		Estimated useful lives

Electricity generating facilities		$	1,543		15 to 50 years
Electricity distribution facilities			13,315		16 to 63 years
Electricity transmission			3,418		27 to 65 years
Natural gas distribution facilities			4,499		28 to 49 years
Natural gas transportation			2,365		25 to 45 years
Natural gas storage			280		25 to 48 years
Other			3,403		5 to 40 years

	Total	$	28,823



			At December 31,


			2003				2002

			Carrying		Fair		Carrying		Fair
			amount		value		amount		value
(in millions)
Long-term debt (Note 3):
	PG&E Corporation 6 7/8% Senior Secured Notes		$	600	$	646	$	–	$	–
		Convertible subordinated notes		280		649		280		280
	Utility			4,839		4,905		5,120		4,906
Rate reduction bonds (Note 4)				1,160		1,252		1,450		1,580
Utility preferred stock with mandatory redemption provisions (Note 7)				137		167		137		132


		Hedging			Foreign									Accumulated
		Transaction in			Currency			Retirement						Other
		Accordance with			Translation			Plan						Comprehensive
		SFAS No. 133			Adjustment			Remeasurement			Other			Income (Loss)

Balance December 31, 2000		$	–		$	(4	)	$	–		$	–		$	(4	)
Period change in:
	Cumulative effect of adoption of SFAS No. 133 and interpretations		(243	)		–			–			–			(243	)
	Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133		237			–			–			–			237
	Net reclassification to earnings		42			–			–			–			42
	Other					(1	)		–			(1	)		(2	)

Balance December 31, 2001			36			(5	)		–			(1	)		30
Period change in:
	Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133		(139	)		–			–			–			(139	)
	Net reclassification to earnings		13			–			–			–			13
	Other		–			2			–			1			3

Balance December 31, 2002			(90	)		(3	)		–			–			(93	)
Period change in:
	Mark-to-market adjustments for hedging transactions in accordance with SFAS No. 133		(8	)		–			–			–			(8	)
	Net reclassification to earnings		17			–			–			–			17
	Other		–			3			(4	)		–			(1	)

Balance December 31, 2003		$	(81	)	$	–		$	(4	)	$	–		$	(85	)


			Agreed Upon Interest Rate
			at December 31, 2003
	Amount Owed		(per annum)
(in millions)
Commercial paper claims	$	873		8.216%
Floating rate notes		1,240		8.333%
Senior notes		680		10.375%
Medium-term notes		287		6.560% to 9.200%
Revolving line of credit claims		938		8.750%
Pollution control bonds		814		1.300% to 5.350%
Qualifying facilities		45		5.000%
Other claims		4,625		3.160% to 12.000%

Liabilities subject to compromise at December 31, 2003	$	9,502


Year	Percentage

Until July 15, 2006		106.875	%
July 16, 2006 — July 15, 2007		103.438	%
July 17, 2007 — July 15, 2008		101.719	%


	188 Days			Year Ended			Year Ended
	Ended July 7,			December 31,			December 31,

	2003			2002			2001
(in millions)
Operating revenues ⁽¹⁾	$	786		$	1,766		$	1,622
Income (Loss) before income taxes ⁽¹⁾		(595	)		(4,094	)		69


⁽¹⁾	Amounts shown have been adjusted for intercompany eliminations.


			Balance at
			December 31, 2002
(in millions)
Assets
	Total current assets		$	3,029
	Net property, plant and equipment			2,939
	Total other non-current assets			1,944

		Total assets		7,912

Liabilities
	Debt in default			4,230
	Long-term debt, classified as current			17
	Other current liabilities			2,410

	Total current liabilities			6,657

	Long-term debt			630
	Price risk management			305
	Other non-current liabilities and deferred credits			972

	Total non-current liabilities			1,907

		Total liabilities		8,564

Excess of liabilities over assets			$	(652	)


							Number of		Net Exposure of
							Largest		Largest
	Gross Credit						Customer or		Customer or
	Exposure Before		Credit		Net Credit		Counterparties		Counterparties
	Credit Collateral ⁽¹⁾		Collateral		Exposure ⁽²⁾		>10%		>10%
(in millions)
December 31, 2003	$	165	$	11	$	154		3	$	68
December 31, 2002		288		113		175		2		55


		Net Credit		Percentage of Net
		Exposure ⁽²⁾		Credit Exposure
(in millions)
Credit Quality ⁽¹⁾
December 31, 2003
	Investment grade ⁽³⁾	$	108		70	%
	Non-investment grade		46		30	%

Total		$	154		100	%

December 31, 2002
	Investment grade ⁽³⁾	$	111		63	%
	Non-investment grade		64		37	%

Total		$	175		100	%


			Total		Total
			unrealized		unrealized
(in millions)	Maturity date		gains		losses			Fair value

Year ended December 31, 2003
U.S. government and agency issues		2004-2032	$	47	$	–		$	586
Municipal bonds and other		2004-2034		11		–			147
Equity securities				409		(1	)		790

Total			$	467	$	(1	)	$	1,523

Year ended December 31, 2002
U.S. government and agency issues		2004-2032	$	50	$	–		$	473
Municipal bonds and other		2004-2034		12		(1	)		196
Equity securities				281		(9	)		666

Total			$	343	$	(10	)	$	1,335



	PG&E
	Corporation						Utility

	2003			2002			2003			2002
(in millions)
Projected benefit obligation at January 1	$	(6,738	)	$	(6,091	)	$	(6,732	)	$	(6,047	)
Service cost for benefits earned		(170	)		(140	)		(170	)		(138	)
Interest cost		(446	)		(438	)		(445	)		(435	)
Plan amendments		(135	)		–			(135	)		–
Actuarial loss		(338	)		(418	)		(338	)		(409	)
Settlement		4			1			4			1
Benefits and expenses paid		307			299			307			296

Projected benefit obligation at December 31	$	(7,516	)	$	(6,787	)	$	(7,509	)	$	(6,732	)

Accumulated benefit obligation	$	(6,656	)	$	(6,131	)	$	(6,650	)	$	(6,085	)


Prepaid benefit cost	$	792		$	993		$	792		$	993
Accrued benefit liability		(51	)		(51	)		(45	)		(42	)
Additional minimum liability		(7	)		(2	)		(7	)		(2	)
Intangible asset		–			2			–			2
Accumulated other comprehensive income		7			–			7			–

Prepaid (accrued) benefit cost	$	741		$	942		$	747		$	951



		Pension Benefits						Other Benefits


		December 31,						December 31,

		2003			2002			2003			2002
(in millions)
PG&E Corporation:
	Projected benefit obligation	$	(7,516	)	$	(6,787	)	$	(1,444	)	$	(1,225	)
	Accumulated benefit obligation		(6,656	)		(6,131	)		–			–
	Fair value of plan assets		7,129			6,189			955			763
Utility:
	Projected benefit obligation	$	(7,509	)	$	(6,732	)	$	(1,444	)	$	(1,197	)
	Accumulated benefit obligation		(6,650	)		(6,085	)		–			–
	Fair value of plan assets		7,129			6,153			955			749



	PG&E Corporation									Utility


	December 31,									December 31,

	2003			2002			2001			2003			2002			2001
(in millions)
Service cost for benefits earned	$	170		$	140		$	128		$	170		$	138		$	127
Interest cost		446			438			420			445			435			417
Expected return on Plan’s assets		(507	)		(596	)		(645	)		(507	)		(592	)		(641	)
Amortized prior service cost		56			59			55			56			59			55
Amortization of unrecognized loss		46			(3	)		(83	)		46			(3	)		(82	)
Settlement loss		1			5			–			1			5			–

Net periodic benefit cost (income)	$	212		$	43		$	(125	)	$	211		$	42		$	(124	)


	One-Percentage		One-Percentage
	Point Increase		Point Decrease

Effect on postretirement benefit obligation	$	31	$	(28	)
Effect on service and interest cost		3		(2	)



						Irrigation District &
						Water Agency
		Qualifying Facility								Other
						Operations &		Debt
		Energy		Capacity		Maintenance		Service		Energy		Capacity		Total
(in millions)
2004		$	1,070	$	520	$	41	$	28	$	60	$	36	$	1,755
2005			1,040		520		35		26		27		36		1,684
2006			1,020		510		31		26		27		36		1,650
2007			970		490		30		26		28		35		1,579
2008			940		480		31		26		14		8		1,499
Thereafter			8,300		4,100		182		142		79		49		12,852

	Total	$	13,340	$	6,620	$	350	$	274	$	235	$	200	$	21,019



		Quarter Ended

		December 31			September 30		June 30		March 31
(in millions, except per share amounts)
2003 ⁽¹⁾
PG&E CORPORATION
Operating revenues ^{(1) (2)}		$	2,538		$	3,103	$	2,729	$	2,065
Operating income ⁽¹⁾			317			1,173		780		73
Income (loss) from continuing operations ⁽¹⁾			37			508		328		(82	)
Net income (loss) ⁽⁴⁾			37			510		227		(354	)
Earnings (Loss) per common share from continuing operations, basic			0.10			1.31		0.85		(0.21	)
Earnings (Loss) per common share from continuing operations, diluted			0.09			1.24		0.81		(0.21	)
Common stock price per share:
	High		27.98			24.00		22.01		15.35
	Low		23.43			20.63		13.41		11.69

UTILITY
Operating revenues ⁽²⁾		$	2,538		$	3,103	$	2,730	$	2,067
Operating income			340			1,195		755		49
Net income			62			589		345		(73	)
Income available for common stock			58			583		339		(79	)

2002 ⁽¹⁾
PG&E CORPORATION
Operating revenues ⁽¹⁾		$	2,397		$	2,947	$	2,712	$	2,449
Operating income ⁽¹⁾⁽³⁾			542			1,069		1,071		1,272
Income from continuing operations ⁽¹⁾⁽³⁾			191			479		456		597
Net income (loss) ⁽³⁾⁽⁵⁾			(2,189	)		466		218		631
Earnings per common share from continuing operations, basic			0.50			1.28		1.25		1.64
Earnings per common share from continuing operations, diluted			0.48			1.22		1.23		1.62
Common stock price per share:
	High		14.18			17.75		23.75		23.66
	Low		8.17			8.00		16.35		18.86

UTILITY
Operating revenues		$	2,398		$	2,949	$	2,714	$	2,453
Operating income ⁽³⁾			547			1,059		1,059		1,248
Net income ⁽³⁾			227			527		469		596
Income available for common stock			221			520		463		590