Prepared by R.R. Donnelley Financial -- 2001 Annual Report to Shareholders

PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. PG&E Corporation's energy utility subsidiary, Pacific Gas and Electric Company (the Utility), delivers electric service to approximately 4.8 million customers and natural gas service to approximately 3.9 million customers in Northern and Central California. PG&E Corporation's other significant subsidiary is PG&E National Energy Group, Inc. (PG&E NEG), headquartered in Bethesda, Maryland. On April 6, 2001, the Utility filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code (Bankruptcy Code) in the United States Bankruptcy Court for the Northern District of California (Bankruptcy Court). Under Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The factors causing the Utility to take this action are discussed in this Management's Discussion and Analysis (MD&A) and in Notes 2 and 3 of the Notes to the Consolidated Financial Statements.

PG&E Corporation has identified three reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distribution, the regulatory environment, and how information is reported to PG&E Corporation's key decision makers. These segments represent a change in the reportable segments from those reported in the year 2000. In accordance with accounting principles generally accepted in the United States, prior year segment information has been restated to conform to the current segment presentation. The Utility is one reportable operating segment. The other two reportable operating segments are the Integrated Energy and Marketing (PG&E Energy) and the Interstate Pipeline Operations (PG&E Pipeline) segments of PG&E Corporation's subsidiary, PG&E NEG. These three reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions. Financial information about each reportable operating segment is provided in this MD&A and in Note 17 of the Notes to the Consolidated Financial Statements.

PG&E NEG is an integrated energy company with a strategic focus on power generation, natural gas transmission, and wholesale energy marketing and trading in North America. PG&E NEG and its subsidiaries have integrated their generation, development, and energy marketing and trading activities in an effort to create energy products in response to customer needs, increase the returns from its operations, and identify and capitalize on opportunities to optimize generating and pipeline capacity. PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. The principal subsidiaries of PG&E NEG include: PG&E Generating Company, LLC and its subsidiaries (collectively, PG&E Gen LLC); PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, PG&E Energy Trading or PG&E ET); PG&E Gas Transmission Corporation and its subsidiaries (collectively, PG&E GTC), which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively, PG&E GTN), PG&E North Baja Pipeline, LLC (PG&E NBP), and PG&E Gas Transmission, Texas Corporation and its subsidiaries, and PG&E Gas Transmission Teco, Inc. and its subsidiaries (collectively, PG&E GTT) (see Note 6 of the Notes to the Consolidated Financial Statements for a discussion of the sale of PG&E GTT). PG&E Energy Services Corporation (PG&E ES), which was discontinued in 1999, provided retail energy services. PG&E NEG also has other less significant subsidiaries.

This is a combined annual report of PG&E Corporation and the Utility. It includes separate consolidated financial statements for each entity. The consolidated financial statements of PG&E Corporation reflect the accounts of PG&E Corporation, the Utility, PG&E NEG, and other wholly owned and controlled subsidiaries. The consolidated financial statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled subsidiaries. This combined MD&A should be read in conjunction with the consolidated financial statements included herein.

This combined annual report, including our Letter to Shareholders and this MD&A, contains forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and on assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as "estimates," "expects," "anticipates," "plans," "believes," 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 of 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:

– whether the Bankruptcy Court approves the amended disclosure statement relating to the Utility's proposed plan of reorganization (Plan) to be submitted to comply with the Bankruptcy Court's February 7, 2002 decision;

– whether the Bankruptcy Court confirms the Utility's Plan as amended to comply with the Bankruptcy Court's February 7, 2002 decision;

– whether the Bankruptcy Court confirms the alternative plan of reorganization to be submitted by the California Public Utilities Commission (CPUC) and the terms of such a plan;

– whether other parties submit alternative proposed plans of reorganization after the expiration of the period during which only the Utility may file a proposed plan;

– whether the CPUC takes action that would negatively affect the feasibility of the proposed Plan;

– whether the Utility is required to re-assume the obligation to purchase power for its customers from the California Department of Water Resources (DWR) under circumstances that threaten to undermine the Utility's creditworthiness, financial condition, or results of operation;

– whether the Utility is required to accept assignment of the DWR's power purchase contracts;

– risks relating to the issuance of new debt securities by each of the disaggregated entities, including higher interest rates than are assumed in the financial projections which could affect the amount of cash that could be raised to satisfy allowed claims, and the inability to successfully market the debt securities due to, among other reasons, an adverse change in market conditions or in the condition of the disaggregated entities before completion of the offerings;

– whether a favorable tax ruling or opinion is obtained regarding the tax-free nature of the transactions contemplated in the Plan;

– whether approval is obtained from the various federal regulatory agencies to implement the transactions contemplated in the Plan, the timing of that approval, and the timing and success of any appeals of such regulatory orders;

As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from results or outcomes currently sought or expected.

In this MD&A, we first discuss our earnings guidance, we then discuss the impact of the California energy crisis and the Utility's bankruptcy on our liquidity, and then PG&E NEG's liquidity. We then discuss statements of cash flows and financial resources, and our results of operations for 2001, 2000, and 1999. Finally, we discuss our competitive and regulatory environment, our risk management activities, and various uncertainties that could affect future earnings. Our MD&A applies to both PG&E Corporation and the Utility.

We expect 2002 corporate earnings from operations including headroom, the difference between generation related revenues collected from customers at CPUC-authorized rates and our generation related costs, to be in the $3.00 per share range. (On a regulatory accounting basis, headroom recovers previously uncollected generation related costs that we wrote off at December 31, 2000.)

We are including headroom in earnings guidance for 2002 as a placeholder for increases in operating revenues that could result when the Utility's pending regulatory issues, such as the 2002 attrition rate adjustment, the retained generation ratemaking proceeding, direct access, and others are resolved. On a quarterly basis, we expect the amount of headroom to fluctuate materially due to many factors, including the outcome of regulatory proceedings and other regulatory actions, sales volitility, changes in estimates of previously incurred energy procurement costs, the level of direct access customers, and the impact of the end of the rate freeze period. As a result, it is difficult to predict the amount of quarterly headroom.

Additionally, in light of the economy and energy markets, we expect that contribution to 2002 earnings from PG&E NEG will be down somewhat from 2001 results.

Earnings from operations exclude items impacting comparability and should not be considered an alternative to net income as prescribed by accounting principles generally accepted in the United States.

As discussed below, the California energy crisis has impacted the credit ratings of various debt and equity instruments. The credit ratings as of December 31, 2001, of the various debt and equity instruments of PG&E Corporation, the Utility, and PG&E NEG are summarized in the table below:

		Credit Rating
		Standard and Poors	Moody's Investors Service
PG&E Corporation
	GE/Lehman Loans	Not Rated	Private Rating
Utility
	Mortgage Bonds	CCC	B3
	Pollution Control Bonds—Bond Insurance	AAA	Aaa
	Pollution Control Bonds—Letters of Credit	AA to A+	Not Rated
	Medium-Term Notes	D	Caa2
	San Joaquin Valley Power Authority Bond	Not Rated	Rating W/D
	DWR Loan	Not Rated	Not Rated
	Senior 5-Year Note	D	Caa2
	Revolving Credit Line	Not Rated	Not Rated
	Floating Rate Notes	D	Not Rated
	Matured Commercial Paper	D	Not Prime
	Redeemed Pollution Control Bonds—Bank Loans	Not Rated	Not Rated
	Quarterly Income Preferred Securities (QUIPS)	D	Caa3
	Preferred Stock	D	Ca
PG&E NEG
	Senior Unsecured Notes due 2011 (PG&E NEG)	BBB	Baa2
	Senior Unsecured Notes due 2005 (PG&E GTN)	A-	Baa1
	Senior Unsecured Debentures due 2025 (PG&E GTN)	A-	Baa1
	Medium-Term Notes (nonrecourse) (PG&E GTN)	A-	Baa1
	Outstanding Credit Facilities	Various	Various
	Term Loans-Gen Holdings	BBB-	Baa3
	Mortgage Loans and Others	Not Rated	Not Rated

The California energy crisis described in Note 3 of the Notes to the Consolidated Financial Statements has had a significant negative impact on the liquidity and capital resources of the Utility. Beginning in June 2000, the wholesale price of electric power in California steadily increased to an average cost of $0.182 per kilowatt-hour (kWh) for the seven-month period June 2000 through December 2000, as compared to an average cost of $0.042 per kWh for the same period in 1999. During this period retail electric rates were frozen. The Utility was only permitted to collect approximately $0.054 per kWh in frozen retail rates from its customers to pay for the Utility's generation-related costs. While seeking rate relief from the CPUC, the Utility financed the difference between its wholesale electricity costs and the amount collected through frozen retail rates. By December 31, 2000, the Utility had borrowed more than $3 billion. As of December 31, 2000, the Utility had accumulated a total of approximately $6.9 billion in under-collected wholesale electricity costs and generation-related transition costs. This amount was charged to earnings at December 31, 2000, because the Utility could no longer conclude that such costs were probable of collection through regulated rates.

In January 2001, the CPUC granted an interim rate increase of $0.010 per kWh. This increase, which could not be used to recover past procurement costs, was not sufficient to cover the on-going high wholesale electricity costs then being experienced. As a result of the higher energy prices and the insufficient rate increase, PG&E Corporation's and the Utility's credit ratings deteriorated to below investment grade. These credit downgrades, which occurred on January 16 and 17, 2001, were events of default under one of the Utility's revolving credit facilities and precluded PG&E Corporation's and the Utility's access to the capital markets. Accordingly, the banks

stopped funding under the Utility's revolving credit facility. On January 17, 2001, the Utility began to default on maturing commercial paper obligations. In addition, the Utility was no longer able to meet its obligations to generators, qualifying facilities (QFs), the Independent System Operator (ISO), and the Power Exchange (PX), and began making partial payments of amounts owed.

As of January 19, 2001, the Utility had no credit under which it could purchase power for its customers, and generators were only selling to the Utility under emergency actions taken by the U.S. Secretary of Energy. As a result, the State of California authorized the DWR to purchase electricity for the Utility's customers. California Assembly Bill AB 1X was passed on February 1, 2001, authorizing the DWR to enter into contracts for the supply of electricity and to issue revenue bonds to finance electricity purchases, although the DWR indicated that it intended to buy power only at reasonable prices to meet the Utility's net open position, leaving the ISO to purchase the remainder in order to avoid blackouts. (The net open position is the amount of power needed by retail electric customers that cannot be met by utility-owned generation or power under contract to the Utility).

Throughout the energy crisis, the Utility sought relief through various regulatory proceedings and through efforts to reach a negotiated solution with the State of California ("State"). In late March and early April 2001, the CPUC issued a series of decisions that increased the Utility's inability to recover past debts and increased its exposure to significant additional costs. On March 27, 2001, the CPUC ruled on the Utility's November 20, 2000, request for rate relief. This decision made permanent the $0.010 per kWh interim increase authorized in January 2001 and granted an additional $0.030 per kWh (on average) energy surcharge effective immediately, but that would not be included in customer bills until June 2001. The revenue generated by the rate increase was to be used only for electric power procurement costs incurred after March 27, 2001. This decision ordered the Utility to pay the DWR the full generation-related portion of retail rates for every kWh of electricity sold by the DWR without regard to whether overall retail rates were adequate to recover the remainder of the Utility's cost of service. In the same decision, the CPUC adopted an accounting proposal by The Utility Reform Network (TURN), which retroactively restates the way in which transition costs (those costs believed to be uneconomic are discussed further in Note 3 of the Notes to the Consolidated Financial Statements) are recovered. This retroactive change had the effect of extending the rate freeze and reducing the amount of past wholesale power costs that could be eligible for recovery from customers.

Also on March 27, 2001, the CPUC issued a ruling that required the Utility to begin paying the QFs in full and within 15 days of the end of the QF's billing cycle. On April 3, 2001, the CPUC issued a ruling which adopted a methodology for the Utility to reimburse the DWR for power purchases made to meet the Utility's net open position. The Utility believes this ruling, along with other rulings, illegally compels the Utility to make payments to the DWR and QFs without providing adequate revenues for such payments.

The Utility believes that these actions taken by the CPUC are illegal and the Utility has filed for rehearings and appeals with the CPUC, in federal court, and with the Bankruptcy Court. The status of these proceedings is discussed later in this MD&A.

As discussed further in Note 2 of the Notes to the Consolidated Financial Statements, as a result of (1) the failure of the DWR to assume the full procurement responsibility for the Utility's net open position, (2) the negative impact of a CPUC decision that created new payment obligations for the Utility and undermined its ability to return to financial viability, (3) a lack of progress in negotiations with the State of California to provide a solution for the energy crisis, and (4) the adoption by the CPUC of an illegal and retroactive accounting change that would appear to eliminate the Utility's true under-collected wholesale electricity costs, the Utility filed a voluntary petition for relief under the provisions of the Bankruptcy Code on April 6, 2001.

Under Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. Subsidiaries of the Utility, including PG&E Funding, LLC (which holds the Rate Reduction Bonds) and PG&E Holdings, LLC (which holds stock of the Utility), are not included in the Utility's petition. Neither PG&E Corporation nor PG&E NEG has declared bankruptcy.

The Utility's Consolidated Financial Statements have been prepared in accordance with the American Institute of Certified Public Accountants' Statement of Position (SOP) 90-7, "Financial Reporting by Entities in Reorganization Under the Bankruptcy Code," and on a going concern basis, which contemplates continuity of operation, realization of assets, and liquidation of liabilities in the ordinary course of business. However, as a result of the filing, such realization of assets and liquidation of liabilities are subject to uncertainty.

Certain claims against the Utility in existence before the filing of its bankruptcy petition are stayed while the Utility continues business operations as a debtor-in-possession. The Utility has reflected its total estimate of all such valid claims on the December 31, 2001, Consolidated Balance Sheets as $11.4 billion of Liabilities Subject to Compromise, and as $3.4 billion of Long-Term Debt. Additional claims or changes to Liabilities Subject to Compromise may arise after the filing date resulting from, among other things, resolution of disputed claims and Bankruptcy Court actions. Payment terms for these amounts will be established through the bankruptcy proceedings. Secured claims also are stayed, although the holders of such claims have the right to ask the Bankruptcy Court for relief from the stay. Secured claims are secured primarily by liens on substantially all of the Utility's assets and by pledged accounts receivable from gas customers. The Bankruptcy Court has approved certain payments and actions necessary for the Utility to carry on its normal business operations (including payment of employee wages and benefits, refunds of certain customer deposits, use of certain bank accounts and cash collateral, payments to QFs, assumption of various hydroelectric contracts with water agencies and irrigation districts, interest on secured debt, and continuation of environmental remediation and capital expenditure programs) and to fulfill certain post-petition obligations to suppliers and creditors.

Through September 5, 2001, the last day for non-governmental creditors to file proofs of claim, approximately $42.1 billion of claims had been submitted. This amount includes claims filed by generators (which the Utility believes have been significantly overstated) and claims filed by financial institutions (which the Utility believes contain significant duplication). The Bankruptcy Court so far has disallowed approximately $9 billion of claims filed by non-governmental entities. In addition, through October 3, 2001, the last day for governmental entities to file proofs of claim, approximately $1.9 billion of claims had been submitted. These include, but are not limited to, contingent environmental claims, claims for federal, state and local taxes, and claims submitted by the DWR for approximately $430 million of energy purchases made on behalf of the Utility's retail customers.

The claims resolution process in bankruptcy involves establishment of the validity of the claim and determination of specifically how the claim is to be discharged. In addition, it is very common to negotiate with creditors to achieve settlement. The Utility intends to explore settlement of claims wherever possible.

On September 20, 2001, the Utility and PG&E Corporation jointly filed with the Bankruptcy Court a proposed plan of reorganization of the Utility under the Bankruptcy Code and a proposed disclosure statement describing the proposed plan. Both the plan of reorganization and the disclosure statement were amended on December 19, 2001, and again on February 4, 2002, in an effort to resolve objections that had been filed by various parties. If the amended Plan is confirmed and becomes effective, the Plan would allow the Utility to restructure its businesses, refinance the restructured businesses, and use the proceeds from the refinancing to pay all valid claims with interest (see Note 2 of the Notes to the Consolidated Financial Statements for a complete description of the Plan).

The Plan, which has been endorsed by the Official Committee of Unsecured Creditors and another group of creditors, is designed to align the businesses under the regulators that best match the business functions. Retail assets would remain under the retail regulator (CPUC) and wholesale assets would be placed under wholesale regulators, the Federal Energy Regulatory Commission (FERC) and the Nuclear Regulatory Commission (NRC). After this alignment, the retail-focused, state-regulated business would be a gas and electric distribution company (Reorganized Utility) representing approximately 70 percent of the book value of the Utility's current assets and having approximately 16,000 employees. The wholesale businesses, which would be federally regulated (as to price, terms, and conditions), would consist of electric transmission (ETrans), interstate gas transmission (GTrans), and generation (Gen).

The Plan proposes that certain other assets of the Utility deemed not essential to operations would be sold to third parties or transferred to Newco Energy Corporation (Newco), a consolidated subsidiary created by the Utility to hold the investments in ETrans, GTrans, and Gen. Additionally, the Utility would declare and, after the assets are transferred to the newly formed entities, pay a dividend of all of the outstanding common stock of Newco to PG&E Corporation. Each of ETrans, GTrans, and Gen would continue to be an indirect wholly owned subsidiary of PG&E Corporation.

The Utility's 18,500 circuit miles of electric transmission lines and cable would be transferred to ETrans, a California company. ETrans would operate as an independent transmission company selling transmission services to wholesale customers (utilities) and to electric generators.

The Utility's 6,300 miles of transmission pipelines and three gas storage facilities would be transferred to GTrans, a California company. GTrans would hold the majority of the land, rights of way, and access rights currently associated with Utility gas transmission pipelines. GTrans would also assume certain continuing

contractual obligations currently held by the Utility's gas transmission operation. In addition, the Reorganized Utility would hold a 10- to 15-year transportation and gas storage contract with GTrans.

The Utility's hydroelectric and nuclear generation assets and associated lands, and the power contracts with irrigation districts would be transferred to Gen, a California company. In total, the unit would have approximately 7,100 megawatts (MW) of generation. The facilities would be operated in accordance with all current FERC and Nuclear Regulatory Commission (NRC) licenses. The generating business would sell its power back to the Reorganized Utility under a 12-year contract at a stable, market-based rate.

The Plan, as amended, relies on the FERC and the Bankruptcy Court to authorize certain actions which are outside of management's control. These actions include allowing a shift in jurisdiction of certain of the Utility's assets, approving contracts between and among the newly formed entities, and preempting certain state and local laws. Specifically, the Plan asks the Bankruptcy Court to issue the following orders or make the following findings:

On February 7, 2002, the Bankruptcy Court issued an order concluding that bankruptcy law does not expressly preempt state law in connection with the implementation of a plan of reorganization. Instead, the Bankruptcy Court interpreted the applicable bankruptcy law to impliedy preempt state law where it has been shown that enforcing the state law at issue would be an obstacle to the accomplishment and execution of the full purposes of the bankruptcy laws. The Bankruptcy Court stated that whether a restructuring; i.e., the disaggregation of the Utility's businesses as proposed in the Plan, is necessary and required for a feasible reorganization, is an issue to be determined at the confirmation hearing.

The Bankruptcy Court provided guidance as to how the Plan could be amended to obtain court approval so that the stage would be set for the "implied preemption confirmation contest." The Plan and disclosure statement will be amended to (1) eliminate express preemption provisions so they can proceed to a confirmation hearing where PG&E Corporation and the Utility intend to show that implied preemption of specified statutes is available to confirm the Plan, and (2) state with specificity the facts demonstrating that the state and the CPUC have waived their sovereign immunity, and, in the event the Bankruptcy Court finds that such immunity has been waived, to provide for declaratory and injunctive relief against the state and the CPUC. If the Bankruptcy Court determines that such sovereign immunity has not been waived, the Bankruptcy Court indicated in its February 7, 2002, decision that it would still be able to enforce its confirmation order under certain circumstances. PG&E Corporation and the Utility must file an amended Plan and disclosure statement by March 7, 2002. Objections to the amended Plan and disclosure statement must be filed with the Bankruptcy Court by March 19, 2002. The Bankruptcy Court has scheduled a hearing for March 26, 2002, to consider the adequacy of the amended disclosure statement and to resolve objections.

The CPUC has filed with the Bankruptcy Court a term sheet depicting its alternative plan of reorganization on February 13, 2002. The CPUC's term sheet does not call for realignment of the Utility's business and provides for the continued regulation of all of the Utility's current operations by the CPUC. Other significant components of the CPUC's plan include:

The CPUC's proposed timeline for its alternate plan provides for confirmation hearings to begin on or before September 16, 2002 and for the plan to become effective on or before January 31, 2003.

PG&E Corporation and the Utility do not believe the CPUC's plan is credible because it overstates the available cash, understates the debt and other obligations, and undermines the Utility's ability to invest in electrical system reliability. PG&E Corporation and the Utility also do not believe the CPUC's plan will restore the Utility to Investment grade when the plan becomes effective. On February 27, 2002, the Bankruptcy Court decided to permit the CPUC to formally file its proposed plan. The CPUC must submit its alternative plan by April 15, 2002.

PG&E Corporation and the Utility are unable to predict whether the Bankruptcy Court will confirm the Plan, whether the Bankruptcy Court will confirm the CPUC's alternative plan, or whether other parties may file an alternative plan of reorganization after June 30, 2002 when the period during which only the Utility (except the CPUC) may file a proposed plan will expire. Consideration of alternative plans could cause delays in the Plan's current schedule. PG&E Corporation and the Utility cannot predict what will be in these other parties' plans or whether they will be confirmed by the Bankruptcy Court. Further, assuming the Bankruptcy Court confirms the Plan, implementation may be impacted by appeals, which could also cause delays. Accordingly, the filing for bankruptcy protection and the related uncertainty around the plan of reorganization that is ultimately adopted will have a significant impact on the Utility's future liquidity and results of operations. The Utility is not able at this time to predict the outcome of its bankruptcy case, or the effect of the Chapter 11 reorganization process on the claims of the creditors of the Utility or the interests of the Utility's preferred security holders. However, the Utility believes, based on information presently available to it, that cash and cash equivalents on hand at December 31, 2001, of $4.3 billion and cash available from operations will provide sufficient liquidity to allow it to continue as a going concern through 2002.

The liquidity and financial condition crisis faced by the Utility also negatively impacted PG&E Corporation. Through December 31, 2000, PG&E Corporation funded its working capital needs primarily by drawing down on available lines of credit and other short-term credit facilities. At December 31, 2000, PG&E Corporation had borrowed $185 million against its five-year revolving credit agreement and had issued $746 million of commercial paper. On January 16 and 17, 2001, PG&E Corporation's credit ratings were downgraded along with the Utility's ratings to below investment grade, and the banks refused any additional borrowing requests and terminated their remaining commitments under existing credit facilities. Commencing January 17, 2001, PG&E Corporation began to default on its maturing commercial paper obligations.

On March 1, 2001, PG&E Corporation refinanced its debt obligations with $1 billion in aggregate proceeds from two term loans under a common credit agreement with General Electric Capital Corporation (GECC) and Lehman Commercial Paper Inc. (LCPI). The obligations under the credit agreement are secured by a pledge of PG&E Corporation's interest in PG&E NEG. The credit agreement also provided GECC and LCPI an option to purchase for $1.00 up to a 3 percent ownership interest in PG&E NEG, depending upon how long the loans are outstanding. In accordance with the credit agreement, the proceeds, together with other PG&E Corporation cash, were used to pay $501 million in commercial paper (including $457 million of commercial paper on which PG&E Corporation had defaulted), $434 million in borrowings under PG&E Corporation's long-term revolving credit facility, and $109 million to PG&E Corporation shareholders of record as of December 15, 2000, in satisfaction of a defaulted fourth quarter 2000 dividend. Further, approximately $99 million was used to prepay the first year's interest under the credit agreement and to pay transaction expenses associated with the debt restructuring.

In November 2001 and March 2002, PG&E Corporation signed agreements to amend its current $1 billion aggregate term loan credit facility with GECC and LCPI and their assignees. The original debt obligations entered into on March 1, 2001, permitted PG&E Corporation to extend the term of the credit facility, which would otherwise expire on March 1, 2003, for an additional year. The amendments provide for two additional one-year extensions to the term of the credit facility contingent upon PG&E Corporation making a principal payment of $308 million by June 3, 2002, so that the termination date could be extended to March 2, 2006. As a condition for the exercise of each of the one-year extensions, PG&E Corporation must pay a fee of 3 percent of the then-outstanding balance and also issue to the lenders additional options equal to approximately 1 percent of the common stock of PG&E NEG. If PG&E Corporation extends the term from March 1, 2003, using the initial extension, the fee will be 2 percent of the then-outstanding balances for each six-month period.

The credit agreement with GECC and LCPI provides that a failure to comply with financial covenants will constitute an event of default, after applicable grace periods. These covenants include, among other things, the requirement that PG&E NEG maintain an investment grade credit rating and a ratio of fair market value to the aggregate amount of principal outstanding under the loan of at least 2:1, and that PG&E Corporation maintain a cash reserve of at least 15 percent of the loan balance until March 2, 2004, and 10 percent thereafter, unless interest is prepaid. In addition, failure of PG&E NEG to maintain at least a 1.25:1 ratio of fair market value to loan balance would constitute an immediate event of default and result in acceleration of the loan.

PG&E Corporation itself had cash and short-term investments of $348 million at December 31, 2001, and believes that the funds will be adequate to maintain PG&E Corporation's continuing operations through 2002. In addition, PG&E Corporation believes that it and its non-CPUC regulated subsidiaries are protected from the bankruptcy of the Utility.

The national markets in which PG&E NEG participates are experiencing the first sustained downturn in the electric power commodity business cycle since electric deregulation began in the mid-1990s. Price spikes beginning in 1997 and 1998 culminated in peak prices in 2000 and early 2001. New supply additions begun under the high-price period, combined with a softening economy, have resulted in projected excess energy supply. The price of electricity minus the cost of fuel, or spark spread, available in most regional wholesale energy markets has declined recently, and prices and spark spreads in the forward markets in which PG&E NEG transacts much of its business for its generating portfolio have declined as well.

On December 2, 2001, a major participant in the energy business, Enron Corp. (Enron), filed for protection under Chapter 11 of the U.S. Bankruptcy Code (Enron Bankruptcy). The Enron Bankruptcy had little impact on the energy commodity markets which have remained liquid and efficient. Although Enron was a significant participant

in the energy trading business, a large portion of Enron's transactions was purely financial, thereby minimizing impacts on the physical energy markets. In addition, significant reporting in the public press during the months preceding the Enron Bankruptcy enabled many counterparties, including PG&E NEG, to reduce their exposure to Enron.

In contrast to the minimal impact on the energy trading markets, the Enron Bankruptcy exacerbated uncertainty in the capital markets for energy companies, which was initially triggered by the California energy crisis and the Utility's bankruptcy. Analysts are now expecting improved accounting and reporting standards, and the rating agencies are reviewing the credit quality and credit ratings of many energy companies. Moody's Investors Service (Moody's) has particularly focused on rating triggers and has indicated that it is revising its view of debt to total capitalization levels and other key credit criteria when assigning credit ratings. Continued capital market uncertainty or any lowering of PG&E NEG's credit rating would adversely impact PG&E NEG's access to capital or its cost to access capital and could impede PG&E NEG's growth plans and cash liquidity positions.

A lower level of economic activity may result in a decline in energy consumption and new electric supply additions begun during more robust economic conditions are beginning to commence operation. The combination of decreased consumption and increased supply may result in excess supply and declining operating margins for electric generators. Furthermore, these same factors may result in lower price volatility for energy products, potentially reducing profits from energy trading activities.

In response to these market changes, PG&E NEG may defer, cancel, sell joint ventures in, or otherwise dispose of some or all of its projects in development and the equipment associated with those projects. In connection with PG&E NEG's current revised development plans, it has restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap, or sale of generation projects in development. If PG&E NEG determines to further defer or cancel a project, it may create a mismatch between equipment delivery schedules and development plans. If equipment delivery schedules cannot be adjusted, PG&E NEG may be compelled to choose between paying for equipment in which it would have to store for future use or terminating its commitment to purchase such equipment. If PG&E NEG decides to terminate equipment, then it would incur termination costs to the equipment vendors consisting of amounts shown on the balance sheet plus additional cash payments, if any, due upon termination (Termination Costs). PG&E NEG's exposure for these Termination Costs gradually increases over time. PG&E NEG's cash exposure for Termination Costs would be offset by amounts expended for the equipment through the date of termination.

In December 2000, and in January and February 2001, PG&E Corporation and PG&E NEG completed a corporate restructuring of PG&E NEG, known as a "ringfencing" transaction. The ringfencing involved the creation or use of limited liability companies as intermediate owners between a parent and its subsidiaries. The intermediate owners, which are consolidated in the accompanying financial statements are: PG&E National Energy Group, LLC which owns 100 percent of the stock of PG&E NEG, PG&E GTN Holdings LLC which owns 100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings LLC which owns 100 percent of the stock of PG&E Energy Trading Holdings Corporation. In addition, in March 2001, PG&E NEG's organizational documents were modified to include the same structural elements as those of these new companies. The organizing documents of these new companies require unanimous approval of their respective boards of directors, including at least one independent director, before they can (1) consolidate or merge with any entity, (2) transfer substantially all of their assets to any entity, or (3) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The new companies may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements. After the ringfencing structure was implemented, two independent rating agencies, Standard & Poor's (S&P) and Moody's, reaffirmed investment grade ratings for PG&E GTN and PG&E Gen LLC and issued investment grade ratings for PG&E NEG. S&P also issued an investment grade rating for PG&E ET.

PG&E Corporation normally funds investing activities from cash provided by operations after capital requirements, and, to the extent necessary, external financing. PG&E Corporation's policy is to finance its investments with a capital structure that minimizes financing costs, maintains financial flexibility, and, with regard to the Utility, complies with regulatory guidelines. However, the Utility is currently operating as a debtor-in-possession under Chapter 11 of the Bankruptcy Code. While certain pre-petition debts are stayed, the Utility does not have access to external funding from the capital markets. Additionally, the Utility is in default

under its credit facilities, commercial paper, floating rate notes, senior notes, pollution control reimbursement agreements, and medium-term notes resulting from its failure to pay certain of its obligations. The event of default under each security has been stayed in accordance with the bankruptcy proceedings. The Utility has been making the capital investment in its infrastructure out of cash on hand under supervision of the Bankruptcy Court. It is uncertain whether the Utility will be able to continue to make such necessary capital investment in the future. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of the Chapter 11 bankruptcy filing.

Net cash provided by PG&E Corporation's operating activities totaled $5,300 million, $705 million, and $2,302 million in 2001, 2000, and 1999, respectively. The increase between 2001 and 2000 is primarily attributed to the Utility's pre-petition obligations being stayed under Chapter 11 of the Bankruptcy Code, and deliveries on previously held trading positions at PG&E NEG. The decrease in cash flows from operating activities between 2000 and 1999 is primarily attributed to the Utility's additional electric procurement costs associated with the California energy crisis, with no regulated rate recovery.

Cash used in investing activities was $2,900 million, $1,690 million, and $234 million in 2001, 2000, and 1999, respectively.

During 2001, 2000, and 1999, PG&E Corporation used $2.7 billion, $2.3 billion, and $1.7 billion, respectively, for upgrades and expansions of its facilities in operation or under construction. These capital expenditures were partially offset by the 1999 divestitures of generation facilities at the Utility and by the completed sales of the PG&E ES and PG&E GTT business units in 2000. In 2000, PG&E Corporation sold its energy services retail business for $85 million and its value-added services business and various other assets for $18 million. PG&E NEG received $306 million, which included a working capital adjustment, for the sale of PG&E GTT. The sale also included the purchaser's assumption of liabilities associated with PG&E GTT and debt having a book value of $564 million. In 1999, the Utility received proceeds of $1,014 million from the sale of generation facilities.

PG&E Corporation net cash provided (used) by financing activities totaled $591 million, and $3,075 million and $(1,940) million in 2001, 2000, and 1999, respectively. The Utility and PG&E NEG financing activities are discussed below. In 2001, PG&E Corporation netted $906 million in proceeds from a loan agreement, which, together with cash on hand and from cash operating activities, was used to repay defaulted commercial paper, other loans, and the $109 million in defaulted fourth quarter 2000 dividends. On a consolidated basis, net cash provided by financing activities in 2000 was achieved principally through borrowings under credit facilities and the issuance of short-term and long-term debt needed to fund energy purchases. Overall, net cash used by financing activities in 1999 was used principally to retire debt, repurchase outstanding common stock, and pay dividends.

During 2001, 2000, and 1999, PG&E Corporation issued $15 million, $65 million, and $54 million of common stock, respectively, primarily through the Dividend Reinvestment Plan and the Stock Option Plan component of the Long-Term Incentive Program. During 2001, 2000, and 1999, PG&E Corporation paid dividends on its common stock of $109 million, $436 million, and $465 million, respectively.

During 2001, 2000, and 1999, PG&E Corporation repurchased $0.5 million, $2 million, and $693 million of its common stock, respectively. The 1999 repurchases were executed through separate accelerated share repurchase programs. As of December 31, 1997, the Board of Directors had authorized the repurchase of up to $1.7 billion of PG&E Corporation's common stock on the open market or in negotiated transactions. In February 1999, PG&E Corporation used the remaining funds available under this authorization to purchase 16.6 million shares at a total cost of $531 million. A subsidiary of PG&E Corporation made this repurchase, along with subsequent stock repurchases. The stock held by the subsidiary is treated as treasury stock and is reflected as Stock Held by Subsidiary on the Consolidated Balance Sheets of PG&E Corporation.

In October 1999, the Board of Directors of PG&E Corporation authorized the repurchase of an additional $500 million of PG&E Corporation's common stock on the open market. This authorization supplemented the approximately $40 million remaining from the amount previously authorized. The authorization for share repurchase extended through September 30, 2001. As of December 31, 1999, PG&E Corporation had, through its wholly owned subsidiary, repurchased an additional 7.2 million shares, at a cost of $159 million, under this authorization. PG&E Corporation is precluded by its March 2, 2001, credit agreement with GECC and LCPI from repurchasing any more of its common stock until the loans are repaid.

The following section discusses the Utility's significant cash flows from operating, investing, and financing activities for the three-year period ended December 31, 2001.

Net cash provided by the Utility's operating activities increased to $4,765 million in 2001 from $555 million in 2000. The increase is due to the Utility's pre-petition obligations being stayed under the provisions of Chapter 11 of the Bankruptcy Code (see Note 2 of the Notes to the Consolidated Financial Statements), generation-related revenues exceeding generation-related costs, and the receipt of the 2000 income tax refund of $1.1 billion.

The decrease of $1,625 million between 1999 and 2000 is attributable to the California energy crisis and the significant deterioration of the Utility's financial condition, primarily caused by the electric procurement costs of $6,465 million. These costs have not been recovered from ratepayers.

The primary uses of cash from investing activities were additions to property, plant and equipment. While the Utility is in Chapter 11, these expenditures will be funded from cash provided by operating activities. The Utility's estimated capital spending for 2002 is $1,556 million. The Utility's capital expenditures were $1,343 million, $1,245 million, and $1,181 million for the years ended December 31, 2001, 2000, and 1999, respectively.

During 1999, the Utility sold three fossil-fueled generation facilities and its geothermal generation facilities. These sales closed in April and May 1999, respectively, and generated proceeds of $1,014 million.

Net cash used by financing activities in 2001 was $430 million, reflecting repayment of long-term debt of $401 million, and net repayments under credit facilities and short-term borrowings of $28 million.

While the Utility's bankruptcy case is pending, the Utility is prohibited from paying pre-petition obligations without permission from the Bankruptcy Court. Before the Utility filed its petition, it had paid $18 million related to the maturity of the Utility's various medium-term notes, made net repayments under credit facilities and short-term borrowings of $28 million, and paid $93 million of maturing mortgage bonds. The Utility is current with all interest and sinking fund payments on its mortgage bonds. The Utility also paid $290 million related to the maturity of the Rate Reduction Bonds held by the Utility's wholly owned subsidiary. On February 27, 2002, the Bankruptcy Court approved the Utility's payment of $333 million of mortgage bonds maturing in March 2002.

The Utility maintained a $1 billion credit facility, which is due to expire in November 2002. The unused portion of this facility was cancelled by the bank lending group on January 23, 2001. This facility was previously used to support the Utility's commercial paper program and other liquidity requirements. As of December 31, 2001, the Utility had drawn, and had outstanding, $938 million under this facility to repay maturing commercial paper. In addition, the total defaulted commercial paper outstanding as of December 31, 2001, formerly backed by both this and another now-cancelled facility, was $873 million.

Due to the bankruptcy filing, the Utility is unable at this time to repay its unsecured pre-petition creditors. The Utility has not made interest payments on the following unsecured debt: medium-term notes, $680 million of senior notes, $1,240 million floating rate notes, commercial paper, bank loans, and other unsecured debt. The Utility has not made principal payments on $1,363 million of unsecured debt that matured from April 2001 through December 2001. The Utility is accruing interest on all unpaid debt obligations and compounding interest at interest rates described in the Plan.

The Utility's pollution control loan agreements are primarily secured by irrevocable letters of credit (LOC). As a result of the voluntary petition for Chapter 11, the Utility is in default under the credit providers' reimbursement agreements. Consequently, $454 million of the pollution control loan agreements were declared due and payable, and were funded by drawdowns on the LOCs. Interest payments are current on the remaining $814 million of pollution control loan agreements.

Net cash provided by financing activities in 2000 was $1,937 million, primarily due to net borrowings under the credit facilities and short-term borrowings of $2,630 million and five-year fixed-rate note issues of $680 million,

partially offset by the repayment of long-term debt of $597 million, common stock repurchased of $275 million, and dividends paid of $475 million.

The Utility drew on its credit facility in the amount of $614 million and issued commercial paper of $776 million in 2000. Also, in November 2000, the Utility issued $1,240 million of 364-day floating rate notes.

The Utility's long-term debt that either matured, was redeemed, or was repurchased during 2000 totaled $597 million. Of this amount, (1) $110 million related to the maturity of its 6.63 percent and 6.75 percent mortgage bonds, due June 1, and December 1, 2000, respectively, (2) $81 million related to the Utility's repurchase of various pollution control loan agreements, (3) $113 million related to the maturity of the Utility's various medium-term notes, (4) $3 million related to the other scheduled maturities of long-term debt, and (5) $290 million related to maturity of Rate Reduction Bonds.

In April 2000, a subsidiary of the Utility repurchased from PG&E Corporation 11.9 million shares of its common stock at a cost of $275 million in order to maintain its authorized capital structure. During 2000 and 1999, the Utility did not redeem or repurchase any of its preferred stock.

Net cash used by financing activities in 1999 was $2,256 million and resulted from net repayments under the credit facilities and short-term borrowings of $219 million, repayment of long-term debt of $672 million, common stock repurchased of $926 million, and dividends paid of $440 million.

The Utility's long-term debt that either matured, was redeemed, or was repurchased during 1999 totaled $672 million. Of this amount, (1) $290 million related to the Rate Reduction Bonds maturing, (2) $135 million related to the Utility's repurchase of mortgage and various other bonds, (3) $147 million related to the maturity of various Utility mortgage bonds, and (4) $100 million related to the maturities and redemption of various of the Utility's medium-term notes and other debt.

In December 1999, 7.6 million shares of the Utility's common stock, with an aggregate purchase price of $200 million, were purchased by a subsidiary of the Utility. These repurchases are reflected as Common Stock Held by Subsidiary on the Consolidated Balance Sheets of the Utility. Earlier in 1999, the Utility repurchased from PG&E Corporation and cancelled 20 million shares of its common stock for an aggregate purchase price of $726 million, in order to maintain its authorized capital structure.

PG&E Energy and PG&E Pipeline business sectors require substantial amounts of liquidity and capital resources to support construction, working capital, and counterparty credit requirements. PG&E NEG's strategy is to finance operations using a combination of funds from operations, equity, long-term debt (secured directly by those assets without recourse to other entities), long-term corporate borrowings in the capital markets, operating leases and short and medium term bank facilities that provide working capital, letters of credit and other liquidity needs. During 2001, PG&E NEG took steps to enhance its liquidity and therefore at December 31, 2001, PG&E NEG had $725 million in cash and approximately $800 million available in unused credit lines.

Neither PG&E NEG nor PG&E Corporation require approval of lenders to sell to third parties all or a portion of the equity of a number of lower level subsidiaries, including those holding advanced development projects, so long as PG&E NEG retains the proceeds as cash, uses the proceeds to pay down debt or reinvests the proceeds in the business. Options that PG&E NEG is currently evaluating for raising equity include: a private placement of common or preferred equity, the sale of all or a portion of certain projects in operation or development, and the issuance of equity in an entity that holds a selected group of generating projects, primarily including projects currently in advanced development. At present, PG&E NEG is unable to sell equity securities in the SEC registered public markets due to market conditions or circumstances of the Utility and PG&E Corporation.

Funds from operations come from distributions from PG&E NEG's subsidiary companies. Cash flow distributions from subsidiaries are subject to various debt covenants, organizational by-laws, and partner approvals that can restrict these entities from distributing cash to PG&E NEG unless, among other things, debt service, lease obligations, and any applicable preferred payments are current, the applicable subsidiary or project affiliate meets certain debt service coverage ratios, a majority of the participants approve the distribution, and there are no events of defaults. In addition, the subsidiaries that own PG&E NEG's natural gas transmission facilities and its energy trading businesses have been "ringfenced" and cannot pay dividends unless the subsidiary's board of directors, or board of control, including its independent director, unanimously approves the dividend payment, and the subsidiary has either a specified investment grade credit rating or meets a consolidated interest coverage ratio of greater than or equal to 2.25 to 1.00 and a consolidated leverage ratio less than or equal to 0.70 to 1.00.

During 2001, PG&E NEG generated net cash from operating activities of $405 million. Net cash from operating activities before changes in working capital accounts and price risk management assets and liabilities was $125 million. This increase was principally due to the improved results of operations in 2001 offset by the timing of deferred tax benefits and lower distributions from unconsolidated affiliates. Net cash inflow related to the change in inventories, prepaid expenses, deposits, restricted cash, and other was $83 million, while the change in accounts receivables, accounts payable, and accrued liabilities increased cash flow by $42 million. Change in price risk management assets and liabilities increased cash flow by $155 million. Operating cash flows include payments of $81 million under power purchase agreements, a portion of which is offset by cash receipts from long-term receivables reflected in investing activities.

During 2000, PG&E NEG generated net cash from operating activities of $172 million. Net cash from operating activities before changes in working capital accounts and price risk management assets and liabilities was $267 million. This increase was principally due to the timing of deferred tax benefits and higher distributions from unconsolidated affiliates. Net cash related to the change in inventories, prepaid expenses, deposits, restricted cash, and other was reduced by $139 million, while the change in accounts receivables, accounts payable, and accrued liabilities increased cash flow by $65 million. The change in price risk management assets and liabilities decreased cash flow by $21 million. Operating cash flows include payments of $75 million under power purchase agreements, a portion of which is offset by cash receipts from long-term receivables reflected in investing activities.

During 1999, PG&E NEG generated net cash from operations of $88 million. Net cash from operating activities before changes in working capital accounts and price risk management assets and liabilities was $198 million. This increase was principally due to improved operations offset by the timing of deferred tax benefits. Net cash related to the change in inventories, prepaid expenses, deposits, restricted cash, and other was an increase of $109 million, while the change in accounts receivables, accounts payable, and accrued liabilities decreased cash flow by $98 million. The change in price risk management assets and liabilities decreased cash flow by $121 million. Operating cash flows include payments of $66 million under power purchase agreements, a portion of which is offset by cash receipts from long-term receivables reflected in investing activities.

During 2001, PG&E NEG used net cash of $1.6 billion for investing activities which were primarily attributable to capital expenditures associated with generating projects in construction and advanced development and turbine and other equipment commitments.

During 2000, PG&E NEG used net cash of $864 million for investing activities. Primary cash outflows from investing activities were for capital expenditures of $900 million and the acquisition of Attala Generating Company LLC (Attala) for $311 million in cash. These outflows were partially offset by the receipt of $442 million in proceeds from sales of assets and equity investments.

During 1999, PG&E NEG used net cash of $180 million for investing activities. Investing activities in 1999 consisted principally of $267 million in capital expenditures, partially offset by proceeds from the sale of assets or equity investments of $90 million.

During 2001, PG&E NEG entered into a series of financial transactions to support the construction and acquisition of new assets, finance equipment deposits, refinance existing indebtedness, and provide liquidity and working capital for energy trading and other business activities. These credit facilities have been reviewed by S&P and Moody's, in establishing and maintaining the credit ratings of PG&E NEG and its subsidiaries.

PG&E NEG and its subsidiaries maintain the following credit facilities, and have undertaken the following major financings.

On May 22, 2001, PG&E NEG completed an offering of $1 billion in senior unsecured notes (Senior Notes) and received net proceeds of approximately $972 million after bond debt discount and note issuance costs. PG&E NEG has used a portion of the net proceeds and intends to use the balance of the net proceeds to pay down existing revolving debt, to fund investment in generating facilities and pipeline assets, and for working capital requirements and other general corporate requirements. These Senior Notes bear interest at 10.375 percent per annum and mature on May 16, 2011.

In May 2001, PG&E NEG established a revolving credit facility of up to $280 million to fund turbine payments and equipment purchases associated with its generation facilities. The facility is due to be fully repaid on December 31, 2003. As of December 31, 2001, PG&E NEG had borrowed $221 million against this total borrowing capacity.

PG&E NEG maintains various revolving credit facilities at subsidiary levels which currently are available to fund its capital and liquidity needs. PG&E NEG's generation operation maintains a $100 million revolving credit facility which expires in September 2003. PG&E GTN maintains a $100 million revolving credit facility that expires in May 2002. Outstanding loans on these two facilities are charged London Interbank Offering Rate (LIBOR)-based interest rates, with an interest rate spread over LIBOR tied to the credit rating of the applicable subsidiary and the amount drawn on the facility. As of December 31, 2001, PG&E NEG had borrowed $160 million against its $200 million borrowing capacity under these facilities.

In August 2001, PG&E NEG arranged a $1.25 billion working capital and letter of credit facility consisting of $500 million with a two-year term and $750 million with a 364-day term maturing in August 2003 and August 2002, respectively. PG&E NEG uses this facility to provide working capital and liquidity to its businesses, for letters of credit to fund development and early phase construction expenditures, and for other general corporate purposes. Outstanding loans under this facility are charged LIBOR-based interest rates and an interest rate spread over LIBOR tied to PG&E NEG's credit ratings. On December 31, 2001, $115 million of letters of credit were outstanding under this facility (with a maximum capacity to issue $650 million) and borrowings of $330 million were outstanding under this facility.

In September 2001, PG&E NEG closed a $69.4 million non-recourse secured five-year project financing for the construction of the Plains End generating project in Colorado. As of December 31, 2001, there was $23.3 million outstanding under this financing. As of December 31, 2001, PG&E NEG had invested $16.2 million in the Plains End project and had a payment guarantee to the construction contractor of $5 million.

In December 2001, PG&E NEG closed a new $1.075 billion five-year non-recourse project financing for the GenHoldings I, LLC portfolio of projects secured by the Millennium, Harquahala, and Athens projects. PG&E NEG has provided a guarantee of the equity commitment for these projects of $701 million, of which $251 million remains to be contributed. The equity is scheduled to be funded pro-rata with the debt at a 60/40 debt/equity ratio, although equity infusions could be triggered earlier by a downgrade of PG&E NEG's unsecured debt to below investment grade by both S&P and Moody's, or the failure to meet certain debt covenants of the unsecured debt. This financing was used to reimburse PG&E NEG and repay debt to pay for a portion of the construction costs already incurred on these projects, and will be used to fund a portion of the balance of the construction costs through completion. As of December 31, 2001, there was $449.5 million outstanding under this financing. PG&E NEG has contributed $450 million of equity-in-kind in the form of the Millennium project and partial construction of the Athens and Harquahala projects to GenHoldings I, LLC, and is committed to contribute additional equity during the construction period, which is projected to be completed by the third quarter of 2003.

Cash flow from financing activities by PG&E NEG were $1,140 million, $1,202 million, and $152 million in 2001, 2000, and 1999, respectively. Net cash provided by financing activities in 2001 related to the net proceeds received from the issuance of the Senior Notes partially offset by repayments of amounts borrowed under credit facilities.

During 2000, net cash provided by financing activities was $1,202 million. Net cash provided by financing activities resulted primarily from capital contributions by PG&E Corporation of $608 million, partially offset by distributions of $106 million and other items.

During 1999, net cash provided by financing activities was $152 million. This amount includes borrowings and debt issuances totaling $463 million. PG&E NEG declared and paid to PG&E Corporation a dividend of $111 million in 1999. During 1999, PG&E NEG also repaid a total of $269 million of long-term debt, including PG&E GTT mortgage bonds and senior notes.

PG&E Corporation has numerous outstanding contractual obligations and commitments which include those for capital spending, debt principal payment provisions, electricity, gas purchasing transportation and pipeline capacity, nuclear fuel components, operating leases, tolling agreements, turbine purchases, project financing, and guarantees with counterparties. At December 31, 2001, the following table provides information about PG&E Corporation's contractual obligations and commitments.

The Utility has contractual commitments for the supply of electricity and gas. Under current CPUC regulations, electric energy and capacity are provided by independent power producers that are QFs, irrigation districts, and water agencies. Natural gas is provided by gas suppliers in the western U.S. under contracts of varying lengths, and transportation to California is provided under long-term supply and transportation service contracts with various Canadian and U.S. interstate pipeline companies. In addition, the Utility has purchase agreements for nuclear fuel components and services for use in its Diablo Canyon Nuclear Power Plant.

As a result of the California energy crisis and the Utility's bankruptcy filing, a number of QFs requested the Bankruptcy Court to either terminate their contracts requiring them to sell power to the Utility, or have the contracts suspended for the summer of 2001 so the QFs could sell power at market-based rates. In July 2001, the Utility signed five-year agreements with 197 of its QFs, ensuring the Utility and its customers would receive a reliable supply of electricity at an average energy price of $0.054 per kWh. Under the terms of these assumption agreements, the Utility will assume the pre-petition debt on these 197 QF contracts, totaling $845 million, on the effective date of the plan of reorganization. The total amount the Utility owed to QFs when it filed for bankruptcy protection was approximately $1 billion. The agreements represent 85 percent of debt owed to QFs. For certain of these QFs, if the effective date has not occurred by July 15, 2003, the Utility will pay 2 percent of the principal amount of the pre-petition debt per month until the effective date of the Utility's plan of reorganization or until July 15, 2005, when it will pay the remaining pre-petition debt.

In December 2001 and January 2002, the Bankruptcy Court approved supplemental agreements entered into between the Utility and several QFs to resolve the issue of the applicable interest rate to be applied to the pre-petition debt. The supplemental agreements modify the assumption agreements by (1) setting the interest rate for pre-petition debt at 5 percent per annum; (2) providing for a "catch-up payment" of all accrued and unpaid interest (calculated from the date of default through December 3, 2001) that was paid on December 31, 2001, and (3) providing for an accelerated payment of the principal amount of the pre-petition debt (and interest thereon) in 12 equal monthly payments of principal (and interest thereon) commencing on December 31, 2001, and continuing through November 30, 2002, or, in the event the effective date of the plan of reorganization occurs before the last monthly payment is made, the remaining unpaid principal and accrued but unpaid interest thereon, shall be paid in full on the effective date. The Utility believes that, similar to the experience with the assumption agreements, a large number of the QFs will also wish to enter into similar supplemental agreements.

In addition to the contractual obligations and commitments disclosed above, capital expenditures are expected to be $1,556 million in 2002. In addition, the Utility is required to pass-through certain generation-related revenues to the DWR. These revenues are based on rates established by the CPUC and volumes delivered by the DWR for the Utility's net open position.

The Utility believes that its contractual cash obligations will be met primarily through cash from operations and future financings obtained as a result of the plan of reorganization. For additional discussion of the Utility's commitments, see Note 15 of the Notes to the Consolidated Financial Statements.

The projects that PG&E NEG develops typically require substantial capital, and PG&E NEG has made a number of firm commitments associated with its planned growth of owned and controlled generating facilities, as well as its pipelines. These include commitments for projects under construction, commitments for the acquisition and maintenance of equipment needed for projects under development, payment commitments for tolling arrangements, and forward sale and purchase commitments associated with energy marketing and trading activities.

PG&E NEG currently has six projects under construction. The construction commitments generally relate to facility engineering, construction and procurement, and other related contracts.

To support its development program, PG&E NEG has contractual commitments and options for turbines and related equipment. Most significantly, PG&E NEG has secured contractual commitments and options for

combustion turbines and related equipment representing approximately 14,000 MW of net generating capacity, including 3,868 MW in greenfield development.

In 2000, PG&E NEG entered into agreements with two master turbine trusts, created to own and facilitate the development, construction financing and leasing of generating facilities that will use 41 turbines to be manufactured by General Electric and Mitsubishi. PG&E Corporation and PG&E NEG committed to provide up to $314 million in equity to meet PG&E NEG's obligations to the trusts. As of May 29, 2001, the trusts had incurred $216 million of expenditures. On May 29, 2001, PG&E NEG used $216 million of its new $280 million revolving credit facility to purchase the turbines from the master turbine trusts. As of December 31, 2001, PG&E NEG has borrowed $221 million against the total borrowing capacity of this facility. The facility is due to be fully repaid on December 31, 2003.

PG&E NEG has entered into, long-term service agreements for the maintenance and repair of its combustion turbine or combine cycle generating plants. These agreements are for periods up to 18 years.

PG&E NEG's advanced developed projects are natural gas-fired combined-cycle generation facilities and consist of the following:

These projects were all planned for operation in 2004, with construction starting prior to mid 2002. Recent changes in the power markets have caused PG&E NEG to defer these projects. As a result of a review of the market conditions for new generation, PG&E NEG expects to delay all of its development projects, and swap or sell some of its generation projects under development. In the case of projects that it does retain, PG&E NEG intends to manage its permit and equipment commitments to enable it to delay the start of construction until market conditions warrant, generally between 12 and 36 months from the original plan. Delaying development projects, including Mantua Creek, will result in capital expenditure savings of approximately $1 billion in each of the years 2002 and 2003.

Development has largely been completed for the Mantua Creek project and it is ready to begin construction. PG&E NEG has entered into a construction contract for the facility and released the contractor to perform a limited amount of early construction activities. In light of the current market outlook, PG&E NEG is planning to delay construction of this facility for at least 12 months. As of December 31, 2001, PG&E NEG has recorded assets of $168 million for Mantua Creek, representing equipment payments, construction activities and development costs. PG&E NEG has commenced negotiations with construction contractors and other parties to the project in order to address this delay. If PG&E NEG is not able to reach agreement with these parties and decides to abandon the project, it will be required to write-off approximately $110 million of capitalized and termination costs. This amount does not include major equipment costs. If PG&E NEG is able to reach agreement with these parties, PG&E NEG could defer its near-term capital expenditures, including equipment. In either the deferral or cancellation scenario, PG&E NEG would not incur capital expenditures of approximately $293 million in 2002 and $140 million in 2003.

The following table describes the turbines for which contractual commitments or options exist:

The agreement with Mitsubishi includes steam turbines and heat recovery steam generators. For the General Electric turbines, PG&E NEG has entered into separate agreements with Hitachi to supply such equipment. PG&E NEG also has agreements with Hitachi for long lead-time main step-up transformers for both the Mitsubishi and General Electric equipment.

As a result of continuing review of its development program, PG&E NEG may defer, cancel, sell, joint venture, or otherwise dispose of some or all projects in development and the equipment associated with those projects. In connection with its current revised development plans, PG&E NEG has restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap, or sale of generation projects in development. If further projects are deferred or canceled a mismatch between equipment delivery schedules and development plans may be created. If equipment delivery schedules cannot be adjusted, PG&E NEG may be compelled to choose between paying for equipment which would have to be stored for future use or terminating the commitments to purchase the equipment. If commitments to purchase the equipment are terminated, PG&E NEG would incur termination costs to the equipment vendors consisting of amounts shown as assets on the Consolidated Balance Sheets plus all additional cash payments, if any, due upon termination. Exposure for these equipment termination costs gradually increases over time. Cash exposure for termination costs is offset by amounts expended for the equipment through the date of termination.

Generally, each equipment supply contract allows cancellation of any or all of the commitments to purchase the equipment for a predefined cost. To date, equipment commitments or options have not been cancelled. PG&E NEG continues to work with its vendors to defer payments, delay increases of termination fees, and revise equipment delivery dates. PG&E NEG has good relationships with its vendors and has to date, been largely successful in these efforts. However, there is no assurance that PG&E NEG will be able to continue to modify these agreements to minimize the termination costs and match equipment deliveries with its evolving development plans. The estimates of PG&E NEG's exposure for termination costs are, in part, based upon current contractual arrangements and amendments thereto, which PG&E NEG is confident will be implemented.

Without any further delays or agreements with the equipment vendors, PG&E NEG's committed costs for equipment related to its entire development program, except Mantua Creek (discussed below) are approximately $18 million in 2002, and $160 million in 2003. Aggregate equipment termination costs for the entire development program other than Mantua Creek were $247 million as of December 31, 2001, and are estimated to increase to $254 million at December 31, 2002, and $368 million at December 31, 2003. PG&E NEG has recorded $221 million (excluding Mantua Creek) of prepayments for equipment as of December 31, 2001.

PG&E NEG is currently marketing its development projects for potential sale. If a buyer is found which is willing to purchase equipment which may be used with a purchased project, and PG&E NEG is able to comply with the conditions in its equipment contracts, termination costs can be avoided. However, there can be no assurance that PG&E NEG will be successful in selling any or all of these projects or that the buyers will be able or willing to undertake the equipment purchase obligations.

The amounts set forth in the Commitments and Capital Expenditures Table above are based upon the current contractual provisions assuming all development projects under construction on the schedule set forth in such

contracts. These schedules remain subject to change and the commitments may be deferred or cancelled by contract terms.

Many of the turbine purchases and commitments use the latest generation of combustion technology, which is commonly known as G technology. These G technology turbines are designed to result in higher capacity utilization, lower cost output and a 2 percent to 4 percent higher combustion efficiency than the F technology turbines generally being deployed in most new generating facilities in North America. PG&E NEG has also secured rights to 23 7FB turbines from General Electric. These turbines are expected to be slightly less efficient than G technology turbines, but are designed to have 1 percent or 2 percent higher combustion efficiency than the more standard F technology turbines. In light of its deployment of advanced technology, PG&E NEG has also arranged with each of its turbine vendors for long-term service agreements. These agreements have predetermined pricing, and cover the schedule for major overhauls, parts and associated labor, for at least ten years.

Two of the suppliers of G technology turbines have encountered problems in their initial commercial installations of these turbines. The Lake Road and La Paloma facilities are being constructed by Alstom Power, Inc. (Alstom). Alstom has advised that it may take up to three years to develop and implement modifications to its G technology turbines that are necessary to achieve the guaranteed level of efficiency and output. It is expected that the Lake Road and La Paloma facilities will begin commercial operations at reduced performance and output levels because of the technology issues with Alstom's G technology turbines. Start-up problems were also encountered with the Siemens Westinghouse G technology installed in the Millennium facility. These problems delayed the original date of commercial operations for this facility, which began commercial operations in April 2001. Commercial operations commenced, pursuant to a settlement among Millennium, Bechtel and Siemens which, among other things, deferred fuel oil commissioning and testing. The facility has not yet demonstrated satisfactory performance using fuel oil and availability has been hampered by continuing new technology issues. It is not expected that the start-up and initial operations problems with the Siemens Westinghouse G technology turbine installed at the Millennium facility will result in a long-term, reduction of performance below guaranteed levels of efficiency or output. The construction contracts for each of the Millennium, Lake Road and La Paloma projects provide for liquidated damages that significantly, but not fully, offset the financial impact associated with the delays of these turbines in achieving their expected level of performance.

Alstom has fallen significantly behind its construction schedule on the Lake Road and La Paloma facilities and is paying liquidated damages for such delay. Alstom is implementing a recovery plan with a target commercial operations date in the first half of 2002 for Lake Road and the end of 2002 for La Paloma. In addition, it is expected that the Lake Road facility will not be able to operate on fuel oil until after commercial operations commence. The ability to operate on fuel oil is contemplated in Lake Road's permit from the State of Connecticut. La Paloma is designed to use only natural gas.

PG&E NEG has provisions in some of its financial arrangements that require it or a specified affiliate to maintain certain ratings from S&P and/or Moody's. These provisions are referred to as "rating triggers." The specifics of the ratings that are required to be maintained, the remedy and cure periods should an event of downgrade occur, and the results if PG&E NEG does not take certain actions as a result, differ with each agreement. These provisions generally require PG&E NEG to provide cash to meet outstanding obligations or post cash or a letter of credit as collateral in the event that PG&E NEG could not provide other acceptable replacement security.

PG&E NEG's most significant rating triggers related to its loans include the following:

There are also rating triggers in certain energy trading related guarantees and guarantees to third parties. These are discussed below under Guarantees Supporting Trading Related Agreements.

In September 2001, PG&E NEG closed on a $69.4 million non-recourse secured five-year project financing for the construction of the Plains End generating project in Colorado. At December 31, 2001, there was $23.3 million outstanding under the facility. At December 31, 2001, PG&E NEG had invested $16.2 million in the Plains End property, and had a payment guarantee to the construction contract of $5 million.

The emissions guarantee for particulate matter provided by the construction contractor on the Plains End facility does not use the same test method as required by the facility's air permit. PG&E NEG is currently seeking to modify its air permit emissions rates to address this issue. Pending the receipt of such modification, and demonstration or guarantee from the construction contractor that the facility can comply with the particulate matter emissions rates as modified. PG&E NEG's lenders have withheld funding for construction of the facility. The construction contractor has agreed to continue work and defer pay until March 15, 2002, which is the date that PG&E NEG expects the requested air permit modification will be issued.

PG&E NEG has entered into a number of long-term tolling agreements. Under tolling agreements, PG&E NEG, at its discretion, supplies fuel to a power plant owned by a third party, then sells the output in the competitive market. The power plant owner receives a fee for converting the fuel into electricity. As of December 31, 2001, its annual estimated committed payments under these contracts ranged from $33 million to $211 million, resulting in total committed payments over the next 27 years of approximately $4 billion. PG&E NEG provides payment guarantees under each of these agreements and receives performance availability guarantees from its counterparties. As of December 31, 2001, PG&E NEG has extended about $600 million of such guarantees with an initial face value varying from $20 million to $250 million declining over time as the future obligation declines. Each of these guarantees contains a trigger event provision that requires PG&E NEG to replace the guarantee or provide alternative collateral in the event that its credit rating drops to below investment grade as measured by S&P or Moody's. Although the face value of these guarantees is significant, the exposure in the event of a default is generally limited to payment of the difference between the value of the current tolling agreement and the value of a substitute tolling agreement that the counterparty could enter into at market terms. As of December 31, 2001, the net exposure under the guarantee supporting tolling agreements was 3.2 percent or $20 million. PG&E NEG intends to work with tolling counterparties to amend existing agreements to replace the rating triggers with various covenant packages. Any success in these efforts will depend on the unanimous cooperation of multiple parties.

The construction costs of both the Lake Road and the La Paloma facilities are being financed under separate lease facilities with substantially similar terms. Under these arrangements, a third-party owner/lessor is financing construction of each facility while PG&E NEG is serving as construction agent. Once each facility is completed, the leases for the projects will begin and will continue up to five years from financial closing. The obligations under these leases will commence at the completion of construction and are estimated to begin in 2002. At the end of each lease, PG&E NEG has the option to extend the lease at fair market value, purchase the project, or act as remarketing agent for the lessor for a sale of the project to a third party. If PG&E NEG acts as remarketing agent for the lessor, then PG&E NEG is obligated to the lessor for up to 85 percent of the project's costs, if the proceeds from the sale are less than the lessor's book value. PG&E NEG has committed to the project lenders to contribute equity of up to $230 million for Lake Road and up to $379 million for La Paloma through the purchase of the portion of project loans secured by guarantees on March 31, 2003. The equity infusions could be triggered earlier by a downgrade of PG&E NEG to below investment grade from both S&P and Moody's or the failure to meet certain debt covenants of either projects.

As of December 31, 2001, project costs subject to these agreements totaled $1,012 million, and total costs for both projects are expected to be approximately $1,149 million. The projects are included in the Consolidated Financial Statements.

Assuming project completion, expected future annual lease payments for these two projects are estimated to range from $18 million to $59 million.

Non-recourse debt at subsidiaries in which PG&E NEG has ownership interests but does not have management control is not consolidated and is not recorded on the balance sheet of PG&E NEG since these entities are accounted for under the equity method of accounting and PG&E NEG has no liability for the repayment of that debt. The total amount of non-recourse debt borrowed by unconsolidated investment entities was approximately $1.1 billion. PG&E NEG has no contingent liabilities or funding obligations to cover these loans, which are secured by the assets of the project entities that incurred the debts and are serviced from the cash flows of these entities.

PG&E NEG, through its subsidiaries PG&E GenLLC and PG&E ET, has entered into various gas supply and firm transportation agreements with various pipelines and transporters to provide fuel transportation services to PG&E NEG's own power plants and other customers. Under these agreements, PG&E NEG must make specified minimum payments each month.

PG&E NEG, through its subsidiaries, assumed rights and duties under several power purchase contracts with third-party independent power producers as part of the acquisition of the New England Electric System (NEES) assets. At December 31, 2001, these agreements provided for an aggregate of 800 MW of capacity. Under the transfer agreement, PG&E NEG is required to pay to NEES amounts due to the third-party power producers under the power purchase contracts.

PG&E NEG and its subsidiaries have entered into several operating lease agreements for generating facilities and office space. Lease terms vary between 3 and 48 years. In November 1999, a subsidiary of PG&E NEG entered into a $479 million sale-leaseback transaction whereby the subsidiary sold and leased back a pumped storage station under an operating lease. Operating lease expense amounted to $54 million, $70 million, and $70 million in 2001, 2000, and 1999, respectively.

PG&E NEG has entered into long-term service agreements for the maintenance and repair of certain of its combustion turbine or combined-cycle generating plants. These agreements are for periods up to 18 years. In addition, PG&E NEG has entered into agreements with certain local governments that provide for payments in lieu of property taxes for certain of its generating facilities.

PG&E NEG's energy marketing, trading, hedging, and risk management operations are conducted with counterparties under various master agreements. These agreements typically provide for reciprocal extension of credit lines based on credit worthiness standards. Net open positions under these agreements are marked-to-market on a routine basis and if the net exposed position including receivables and payables falls outside of the established credit limits, then additional collateral must be provided. Therefore, key components of a successful energy business consist of credit worthiness, liquidity resources, risk management systems that provide current mark-to-market of all open positions, and a strong credit department to evaluate and manage counterparty credit risk.

In addition to guarantee supporting tolling agreements, as of December 31, 2001, PG&E NEG and its subsidiaries provided $2.3 billion of guarantees to counterparties in support of its energy trading operations. This includes provision of fuel and pipeline capacity to, and sale of energy products from its power plants. These guarantees were provided in favor of approximately 200 counterparties to permit and facilitate physical and financial transactions in gas, pipeline capacity, power, coal, and related commodities and services with these entities. Typically, the overall exposure under these guarantees is only a fraction of the face value of the guarantees, since not all counterparty credit limits are fully utilized at any time and there may be no outstanding transactions or financial exposure underlying an outstanding guarantee. PG&E NEG receives similar deposits,

letters of credit, and guarantees as collateral for credit extended by PG&E NEG to these, in many cases, same counterparties. These offsetting exposures can often be netted in lieu of posting alternative collateral. As of December 31, 2001, PG&E NEG's net exposure under its guarantees was approximately 8 percent or about $190 million. This exposure is a contingent obligation that could be called only if PG&E NEG or one of its subsidiaries fails to meet and cure a payment obligation.

The continued acceptability of many of these guarantees is dependent on PG&E NEG's maintaining various standards of creditworthiness. As a result, maintenance of investment grade ratings by one or more rating agencies is an important criterion for PG&E NEG and its subsidiaries. If PG&E NEG or its subsidiaries are downgraded by one or more of the rating agencies, PG&E NEG may be required to provide alternative collateral to replace guarantees that no longer meet the creditworthiness standards of the agreements. Therefore, PG&E NEG and its trading subsidiaries maintain substantial cash balances and credit capacity to provide liquidity to its businesses in the event that open credit limits are exceeded through volatility, or in the event of a credit downgrade.

The amount of exposure under master agreements subject to securitization requirements in the event of a credit downgrade of PG&E NEG or its subsidiaries to below investment grade by one or more rating agencies was approximately 5 percent of the outstanding guarantees or $105 million at December 31, 2001. PG&E NEG manages this risk through maintenance of investment grade credit ratings at several principal operating subsidiaries so that guarantees of one entity could be substituted for another in the event of a credit downgrade of one entity.

PG&E NEG and its subsidiaries have issued in excess of $800 million of guarantees in support of various performance and payment obligations under agreements with third parties. Of these guarantees supporting other agreements with third parties, $485 million have investment grade ratings maintenance requirements. In addition, a number of other agreements have specific security provisions requiring maintenance of investment grade ratings. In the event of a downgrade below the trigger level and exhaustion of any cure period, some of these agreements would allow the counterparty to demand payment for any outstanding obligations or contract termination penalties, if any. Others simply provide the counterparty with a right to terminate the contract.

PG&E GTN is in the process of completing its 2002 Expansion Project, which when completed will expand its system by approximately 217 million cubic feet (Mcf) per day. Approximately 40 Mcf per day of that expansion capacity was placed in service in November 2001; the remaining capacity is scheduled to be placed in service by the end of 2002. The total cost of the expansion is estimated to be $122 million. PG&E GTN has filed an application with the FERC for approval to complete a second expansion of approximately 150 Mcf per day of additional capacity, at a cost of approximately $111 million. PG&E GTN expects to fund these expansions from cash provided by operations and, to the extent necessary, external financing and capital contributions from PG&E NEG. PG&E GTN has also initiated a preliminary assessment of a Washington lateral pipeline that would originate at the PG&E GTN mainline system near Spokane, Washington, and extend west approximately 260 miles into the Seattle/Tacoma metropolitan area.

PG&E NEG has entered into a joint development agreement for the development of a new 500 million cubic feet per day gas pipeline, North Baja, to deliver natural gas to Northern Mexico and Southern California. The North Baja project is expected to be completed by the end of 2002. PG&E NEG owns all of the United States section of this cross-border project. PG&E NEG's share of the costs to develop this project will be approximately $146 million. PG&E NEG expects to fund this project from the issuance of non-recourse debt, and available cash or draws on available lines of credit.

As of December 31, 2001, PG&E NEG had replaced or eliminated all of the previously issued PG&E Corporation guarantees, except for an office lease guarantee of $16 million relating to the PG&E NEG's San Francisco office, with a combination of guarantees provided by PG&E NEG or its subsidiaries and letters of credit obtained independently by PG&E NEG. In addition, PG&E NEG has negotiated substitute equity commitments with certain third parties for construction financing agreements, replacing all PG&E Corporation equity commitments included in those agreements. In addition, PG&E NEG has also negotiated substitute equity commitments with certain third parties for construction financing agreements, replacing all PG&E Corporation equity commitments included in those agreements.

PG&E Corporation also has a $2 million guarantee supporting the Utility's investment in low-income housing projects.

The table below shows for 2001, 2000, and 1999 certain items from our Consolidated Statements of Operations and Consolidated Statements of Cash Flows detailed by Utility and PG&E NEG operations of PG&E Corporation. (In the "Total" column, the table shows the combined results of operations for these groups.) The information for PG&E Corporation (the "Total" column) includes the appropriate intercompany eliminations. Following this table, we discuss our results of operations.

PG&E Corporation's results of operations continue to be impacted by the California energy crisis and the Utility's bankruptcy filing. Please see the "Liquidity and Capital Resources" section above, and Notes 2 and 3 of the Notes to the Consolidated Financial Statements for more information.

PG&E Corporation's net income for the year ended December 31, 2001, was $1,099 million, compared to a net loss of $3,364 million for the same period in 2000, representing an increase of $4,463 million. Substantially all of this change was attributable to the Utility.

PG&E Corporation and the Utility expect future earnings to continue to reflect increased volatility as a result of no longer being able to reflect the impact of generation-related regulatory balancing accounts in their financial statements. Financial reporting standards require that these amounts be accounted for as expenses unless they can be deemed probable of recovery. Due to the uncertainty created by the California energy crisis, the Utility cannot meet the accounting probability standard required to defer generation costs for future recovery. As such, costs and revenues historically deferred in regulatory balancing accounts now directly impact net income. The Utility's net income will be impacted by changes in electricity and gas costs, customer demand, weather, costs of operations, conservation, regulatory orders, and other items.

The changes in performance for the years ended December 31, 2001, and 2000, are generally attributable to the following factors:

Net loss for the year ended December 31, 2000, increased to $3,364 million from a net loss of $73 million for the same period in 1999. Of the $3,291 million increase, the Utility's net loss allocated to common stock for the year ended December 31, 2000, accounted for $4,271 million of the increase, partially offset by an increase in PG&E NEG net income of $1,048 million.

The decrease in performance of 2000 compared to 1999 results of operations is attributable to the following factors:

PG&E Corporation's historical quarterly common stock dividend was $0.30 per common share, which corresponded to an annualized dividend of $1.20 per common share.

On January 10, 2001, the Board of Directors of PG&E Corporation suspended the payment of its fourth quarter 2000 common stock dividend of $0.30 per share declared by the Board of Directors on October 18, 2000, and payable on January 15, 2001, to shareholders of record as of December 15, 2000. These defaulted dividends were later paid on March 2, 2001, in conjunction with the refinancing of PG&E Corporation obligations, discussed above under the Liquidity and Capital Resources section. No dividends were declared in 2001. PG&E Corporation's refinancing agreement prohibits dividends from being declared or paid until the term loans have been repaid.

The Utility's income available for common stock was $990 million for 2001, compared to a loss of $3,508 million in 2000. The Utility had higher earnings primarily due to three factors: (1) increased electric revenues, (2) decreased electricity purchase costs, and (3) decreased depreciation, amortization, and decommissioning expenses resulting from the write-off of remaining generation-related regulatory assets and under-collected purchased power costs in 2000.

The Utility's loss allocated to common stock was $3,508 million in 2000 compared to 1999 income of $763 million. The decrease was primarily the result of the write-off of its remaining generation-related regulatory assets and under-collected purchased power costs, a provision for potential litigation losses, and higher income tax expense.

The following table shows the components of the Utility's electric revenue by customer class:

		Year ended December 31,
(in millions)		2001			2000			1999
Residential		$	3,396		$	3,062		$	2,975
Commercial			4,105			3,110			2,980
Industrial			1,554			1,053			1,044
Agricultural			525			420			404

	Total electric revenue		9,580			7,645			7,403
Direct access credits			(461	)		(1,055	)		(348	)
DWR pass-through revenues			(2,173	)		—			—
Miscellaneous			380			264			177

	Total electric operating revenues	$	7,326		$	6,854		$	7,232

Electric revenues in 2001 increased by $472 million, or 6.89 percent, from 2000 and were significantly affected by three factors:

First, there were $594 million fewer direct access credits. In accordance with CPUC regulations, the Utility provides an energy credit to those customers (known as direct access customers) who have chosen to buy their electric generation energy from an energy service provider (ESP) other than the Utility. The Utility bills direct access customers based upon fully bundled rates (generation, distribution, transmission, public purpose programs, and a competition transition charge). However, the direct access customer receives an energy credit equal to the average generation price multiplied by customer energy usage for the period.

At December 31, 2001, the estimated total of accumulated unpaid credits for direct access customers was approximately $506 million, of which $469 million has been classified as subject to compromise on the Utility's Consolidated Balance Sheets. The actual amount that will be refunded to ESPs or directly to the customer will be dependent upon the outcome of the Utility's bankruptcy proceeding, when the rate freeze ends, and whether there are any adjustments made to wholesale energy prices by the FERC.

Second, generation-related surcharges increased revenues but were offset by pass-through revenues collected on behalf of the DWR. Energy procurement surcharges authorized by the CPUC increased revenues by $2,225 million. The increase provided by the surcharges was offset by the pass-through revenues of $2,173 million for electricity that the DWR provided to the Utility's customers. Revenues collected on behalf of the DWR and the related costs are not reflected in the Utility's Consolidated Statements of Operations as the Utility is a collection agent for the DWR. See "California Department of Water Resources" under Note 3 of the Notes to the Consolidated Financial Statements.

Third, conservation efforts by the Utility's customers in response to the California energy crisis, mild weather, and higher prices from the energy surcharge implemented in June 2001 reduced electric sales volumes by 3 percent in 2001 compared to 2000.

Electric revenue in 2000 decreased by $378 million, or 5.23 percent, from 1999 mainly due to industrial and commercial customers receiving direct access credits in 2000. The Utility's electric sales volumes were 3 percent higher in 2000 than 1999, which helped to reduce the effect of the direct access credits on revenues.

The following table shows the components of the Utility's cost of electric energy:

	Year ended December 31,
(in millions)	2001		2000			1999
Cost of electric energy⁽¹⁾	$	2,774	$	6,741		$	2,411
Deferred electric procurement cost		—		(6,465	)		—
Provision for loss on generation - related regulatory assets and under-collected purchased power costs		—		6,939			—

Total cost of electricity expenses	$	2,774	$	7,215		$	2,411

Average cost of electricity per kWh	$	0.059	$	0.093		$	0.034
Total energy purchased and generated (MWh)		46,922		72,261			70,228

The decrease in the total cost of electricity expenses in 2001 of $4,441 million is primarily the result of two factors. First, the Utility was no longer purchasing electricity through the PX market. Instead, the DWR purchased 28,640 megawatt-hours (MWh) of electricity on behalf of the Utility's customers to cover the Utility's net open position in 2001. The cost of the DWR's purchases is not reflected in the Utility's financial statements because the Utility is a collection agent on behalf of the DWR. Second, a statewide energy conservation campaign and mild weather caused the Utility's customers to use approximately 3 percent less energy compared to 2000.

The increase in the total cost of electricity expenses of $4,804 million from 2000 compared to 1999 is primarily attributable to the write-off of the Utility's transition cost regulatory assets and under-collected purchased power costs. In addition, electricity purchase costs increased significantly during the latter half of 2000. The average cost per kWh of electricity was $0.093 per kWh for 2000, whereas revenues for the generation component of frozen rates were approximately $0.054 per kWh. The amount of purchased power costs in excess of the revenue for the generation component of frozen rates was reflected as deferred electric procurement costs prior to the year-end write-off.

In 2001, gas revenues increased $353 million due to a higher average price of gas, which was passed on to customers and collected in gas revenues. The increase was offset by an approximate 4 percent decrease in usage

in 2001 primarily as a result of conservation efforts. The average bundled price of gas sold in 2001 was $10.55 per Mcf compared to $8.40 per Mcf in 2000.

The increase in gas revenues for 2000, compared to 1999 related primarily to higher gas prices. The average bundled price of gas sold per Mcf was $8.40 in 2000 and $5.69 per Mcf in 1999. Gas sales volumes for bundled sales and transportation decreased by 9 percent from 1999 sales volumes due to warmer winter weather, while gas sales volumes for transportation-only service increased by 25 percent due to increased demands by electric generators to meet air-conditioning loads due to warmer summer weather and new transportation contracts.

In 2001, the Utility's cost of gas increased by $407 million principally due the increase in the unit cost of gas to $6.77 per Mcf in 2001 from $5.07 per Mcf in 2000. In addition, the cost of gas increased due to the recognition of losses of $111 million on terminated contracts.

In 2000, the Utility's cost of gas increased compared to 1999 due to increases in the unit cost of gas during the latter half of 2000. The average unit cost of gas that the Utility paid was $5.07 per Mcf in 2000 and $2.39 per Mcf in 1999.

In 2001, the Utility's operating and maintenance expenses decreased by $302 million primarily due to reduced expenses related to the liability for legal matters of $140 million, and lower regulatory and other generation-related costs. In 2000, the Utility's operating and maintenance expenses increased by $165 million primarily due to an increase in the liability for legal matters reserve of $140 million.

Depreciation, amortization, and decommissioning decreased $2,615 million in 2001 from 2000 due to the accelerated depreciation of generation-related assets in 2000, and as a result of less depreciation being recorded in 2001 as the majority of the generation-related assets were fully depreciated after the acceleration.

Depreciation, amortization, and decommissioning increased $1,947 million in 2000 from 1999. The increase resulted primarily from an increase in recovery of transition costs resulting from higher revenues from sales to the PX of Utility-owned generation, including Diablo Canyon generation, and generation from QFs and other providers. As mandated by the CPUC, these revenues, in excess of the related costs, must be used to recover transition costs.

In 2001, the Utility's interest expense increased by $355 million compared to 2000 due to increased debt levels and higher interest rates as a result of the Utility's credit rating downgrade.

In 2000, the Utility's interest expense increased to $619 million from $593 million in response to the additional borrowings of the Utility to pay for the escalated electricity purchase costs in the latter half of 2000.

In accordance with SOP 90-7, the Utility has reported reorganization fees and expenses separately on the Consolidated Statements of Operations. Such costs primarily include professional fees for services in connection with the Chapter 11 proceedings totaling $97 million. In addition, the Utility has incurred other costs related to the California energy crisis of $23 million which have been included in operating and maintenance expenses.

On January 10, 2001, the Utility suspended the payment of its fourth quarter 2000 common stock dividend of $110 million, declared in October 2000, to PG&E Corporation and its wholly owned subsidiary PG&E Holdings, LLC. Until its financial condition is restored, the Utility is precluded from paying dividends to PG&E Corporation and PG&E Holdings, LLC. Dividends on preferred stock are cumulative. Until cumulative dividends on preferred stock are paid, the Utility may not pay any dividends on its common stock.

Dividends paid to PG&E Corporation increased from $440 million in 1999 to $475 million in 2000, in order to maintain the CPUC-mandated capital structure. Dividends paid to preferred shareholders remained at the same level of $25 million in 2000 and 1999.

PG&E NEG's operating income declined $113 million in 2001, primarily due to the sale of PG&E GTT in December 2000 which provided operating income of $77 million in 2000. In addition, PG&E NEG incurred a one-time charge in the fourth quarter of 2001 of $60 million related to the termination of certain contracts resulting from the Enron Bankruptcy (principally related to PG&E NEG's energy trading business). These declines were partially offset by the sale of a development project in the third quarter of 2001, which provided operating income of $23 million and general improvement in operating margins in the Integrated Energy and Marketing segment primarily at the New England region generating facilities.

PG&E NEG's operating income increased $1.5 billion in 2000, as compared to 1999, partially due to a $1.3 billion loss recognized in 1999 as the pre-tax impairment charge to reflect PG&E GTT's assets at their fair value.

PG&E NEG's operating revenues were $12.7 billion in 2001, a decrease of $4.1 billion or 24 percent from 2000. This decline in operating revenues occurred principally within PG&E NEG's Integrated Energy and Marketing segment, and is mainly due to lower trade volumes and lower realized prices achieved primarily in the third and fourth quarters of 2001. These declines generally were due to higher commodity prices in the wake of the California energy crisis in the second half of 2000 and the decline in economic activity in the U.S. in the second half of 2001. In PG&E NEG's Pipeline segment, the decline in operating revenues of $866 million is primarily due to the sale of PG&E GTT in December 2000.

PG&E NEG's operating revenues were $16.8 billion in 2000, an increase of $5 billion, or 42 percent from 1999. This increase occurred principally within PG&E NEG's Integrated Energy and Marketing segment and was primarily the result of the increased volume of electricity and related products and significantly higher prices for both electricity and natural gas. In addition, two New England region generating facilities were not in service for a portion of the summer of 1999. There were no comparable unplanned outages in 2000. Operating revenues for PG&E NEG's Pipeline segment were $1.1 billion in 2000, a decrease of $260 million or 19 percent from 1999. PG&E GTT's revenues decreased $275 million from 1999, as a result of the decrease in natural gas sales resulting from the transfer of certain gas marketing activities conducted by PG&E GTT to the Integrated Energy and Marketing segment in the middle of 1999, and also resulting from 11 months of revenues in 2000 versus a full year of revenues in 1999. This decrease was partially offset by the significant increase in the price of natural gas liquids in 2000.

PG&E NEG's operating expenses were $12.4 billion in 2001, a decrease of $4 billion or 24 percent from 2000. This decline in operating expenses occurred principally in PG&E NEG's energy trading business within the Integrated Energy and Marketing segment, and was mainly due to lower trade volumes and lower realized prices achieved primarily in the third and fourth quarters of 2001. These declines generally were due to higher commodity prices in the wake of the California energy crisis in the second half of 2000 and the decline in economic activity in the U.S. in the second half of 2001. In PG&E NEG's Pipeline segment, the decline in operating expenses of $797 million is primarily due to the sale of PG&E GTT in December 2000.

PG&E NEG's operating expenses were $16.4 billion in 2000, an increase of $3.4 billion or 26 percent from 1999. The increase in operating expenses, which occurred principally in the Integrated Energy and Marketing segment, was mainly due to the increased volume of electricity and other related products and the significantly higher prices of electricity in 2000. This increase was partially offset by lower fuel costs at generating facilities resulting from reduced fuel consumption. In PG&E NEG's Pipeline segment, an impairment charge of $1.3 billion was recognized in 1999 to reflect PG&E GTT's assets at their fair value. This impairment was based on a definitive agreement to sell the stock of PG&E GTT in January 2000. PG&E NEG recorded no comparable impairment or write-offs in 2000.

PG&E Corporation's refinancing agreement prohibits dividends from being declared or paid until the term loans have been repaid. These loan agreements also preclude PG&E NEG from declaring dividends until the term loans have been repaid. The ringfencing transaction referred to above allows PG&E NEG to declare and pay dividends only if PG&E NEG meets certain financial coverage ratios and the dividend is unanimously approved by PG&E NEG's board of directors, which includes an independent director.

A significant portion of PG&E Corporation's operations is regulated by federal and state regulatory commissions. These commissions oversee service levels and in certain cases, PG&E Corporation's revenues and pricing for its regulated services. Following are the percentages of 2001 revenues that fell under the jurisdiction of these various regulatory agencies:

		Utility		Consolidated
Cost of service-based		96.6	%	45.1	%
Market		3.4	%	54.9	%

The Utility is the only subsidiary with significant regulatory proceedings at this time. The Utility's significant regulatory proceedings are discussed below. Regulatory proceedings associated with electric industry restructuring are discussed further in Note 3 of the Notes to the Consolidated Financial Statements.

The CPUC authorizes an amount known as "base revenues" to be collected from ratepayers to recover the Utility's basic business and operational costs for its gas and electric distribution operations. Base revenues, which include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital, currently are authorized by the CPUC in GRC proceedings.

In October 2001, the CPUC issued a decision granting applications for rehearing that had been filed by TURN and another party with respect to the CPUC's February 17, 2000, decision in the Utility's 1999 GRC for the period 1999 to 2001. The applications for rehearing, which had been pending since March 2000, alleged that the CPUC committed legal error by approving funding in certain areas that were not adequately supported by record evidence. In the rehearing decision, the CPUC found that in proposing a general rate increase, the Utility has the obligation to produce clear and convincing evidence for each component of its proposed revenue requirements. The CPUC reversed in part its prior determination regarding the adequacy of the evidence supporting the original 1999 GRC decision, reducing the adopted electric and gas distribution annual revenue requirement by approximately $24.4 million and $14.4 million, respectively.

In addition, the rehearing decision orders the record to be reopened to receive evidence of the actual level of 1998 electric distribution capital spending in relation to the forecast used to determine 1999 rates. This could possibly result in an adjustment of the adopted 1998 forecast level to conform to the 1998 recorded level.

Following the 1998 capital spending rehearing and resolution of all other outstanding matters, a final results of operations analysis will be performed, and a final revenue requirement will be determined. The rehearing decision apparently intends that the revised revenue requirement would be made retroactive to January 1, 1999. Further, in February 2002, the CPUC's consultants began an engineering audit of the Utility's 1999 distribution capital expenditures, as ordered in the CPUC's original February 17, 2000 decision regarding the 1999 GRC. The Utility does not expect a material impact on its financial position or results of operations from the remaining proceedings.

Some of the negative impact of the 1999 GRC rehearing decision was partially offset by a September 20, 2001, CPUC decision. In that decision the CPUC acknowledged that the models used to calculate certain tax items in the Utility's revenue requirements resulted in an incorrect calculation and granted an annual revenue requirements increase of approximately $21 million, representing an increase of $23 million in the gas distribution revenue requirement and a $2 million decrease in electric revenue requirement.

The revised gas revenue requirement resulting from both CPUC actions was retroactive to January 1, 1999, and resulted in a pre-tax income increase of $25.8 million in 2001. The electric revenue requirement charges were retroactive to January 1, 1999, and did not affect net income because the Utility has frozen electric rates.

On November 15, 2001, the Utility filed a petition for a review of the rehearing decision with the California Court of Appeal, as well as an application for rehearing of the rehearing decision with the CPUC. On January 9, 2002, the CPUC denied the Utility's application for rehearing of the rehearing decision.

On February 21, 2002, the CPUC issued a decision authorizing an increase in electric distribution revenue requirements of approximately $151 million, effective January 1, 2001. The increase reflects inflation and the growth in capital investments necessary to serve customers. The 2001 capital-related portion of the increase will be subject to a true-up based on the utility's actual 2001 capital costs. The Utility did not request an increase in gas distribution revenues requirements. Because the Utility had frozen electric rates in 2001 the increase in electric distribution revenue requirements reduced the amount of revenues available to offset electric generation costs. Therefore, the decision has no material current earnings impact.

The procedural schedule in the Utility's 2002 GRC, which would have determined revenue requirements for the period 2002 through 2004, has been delayed. On October 25, 2001, the CPUC issued a decision requiring the Utility to file a Notice of Intent (NOI) to file a 2003 test year GRC (rather than a 2002 test year) by November 14, 2001. The CPUC stated that its goal is to have new rates "in place" by January 1, 2003. A 2003 GRC will determine revenue requirements for the period 2003 through 2005.

In the October 25 order, the CPUC also requested that the Utility and others file comments by November 9, 2001, on the Utility's needs for a 2002 ARA. On November 9, 2001, the Utility filed comments stating its need for a 2002 ARA to allow for recovery of costs of providing electric and gas distribution services. The CPUC has not yet responded to these comments, and has not acknowledged either the Utility's proposal for a process to request an ARA, or the need for interim relief. To the extent the Utility's proposed 2002 ARA is similar to the ARA for 2001, the requested increase will reflect similar annual cost growth as shown in the Utility's 2001 ARA. However, the revenue increase authorized for 2002 will depend on both the amount authorized by the CPUC, and whether and when the CPUC authorizes interim relief. If the CPUC authorizes interim relief for the 2002 ARA, the authorized amount would be prorated for the period extending from the date of the interim authorization to the end of 2002. On January 17, 2002, the Utility filed a motion requesting that the CPUC issue an interim decision authorizing an interim relief mechanism. The Utility also requested that the CPUC specify a process to identify the amount of the ARA requested.

On November 14, 2001, the Utility informed the CPUC that is was impossible to file a fully compliant NOI based on a 2003 test year, considering that it normally takes at least six months to prepare the cost estimates and analyses necessary to develop test-year estimates. On December 11, 2001, the CPUC issued an order to show cause why the Utility should not be penalized for failing to submit the required NOI. The order stated that penalties could be imposed of up to $20,000 per each day the Utility fails to comply with the October 25, 2001, order. On December 20, 2001, the Utility filed a motion with the CPUC to submit its NOI for a 2003 GRC by April 15, 2002. The proposal includes, among other terms, an agreement to pay a voluntary fine of $500 per day beginning January 9, 2002, and concluding on the day the Utility submits its NOI. This proposal is the result of negotiations with the CPUC's staff members. The CPUC has not yet acted upon this proposal.

Further, the Utility believes that the ratemaking for the Utility's Diablo Canyon facility should be based on the specific "benefits sharing" formula established in a 1997 CPUC decision. Under the formula, the Utility would share with ratepayers 50 percent of the net operating benefits or costs of operating Diablo Canyon after the rate freeze. The Incremental Cost Incentive Price (ICIP) ratemaking for Diablo Canyon used to recover the Diablo Canyon facility's operating costs and the cost of capital additions incurred after December 31, 1996 was originally scheduled to end December 31, 2001.

On January 18, 2002, the CPUC issued a proposed decision establishing the Utility's retained generation revenue requirement for 2002. The proposed decision adopts a cost-based 2002 generation revenue requirement for the Utility of $2,875 million subject to adjustment to reflect actual recorded costs (true-up). In addition, the proposed decision rejects the "benefits sharing" ratemaking for Diablo Canyon in favor of cost-based rates that will be subject to a "reasonableness" review in the next GRC. The proposed decision does not reset rates and substantially ignores the Utility's proposed ratemaking, including market-value based recovery for non-nuclear generating facilities and monthly true-ups of operating and maintenance costs.

On February 7, 2002, a CPUC Commissioner issued an alternate proposed decision (AD) regarding the Utility's retained generation revenue requirement proceeding which proposes not to reject benefits sharing for Diablo Canyon but would defer that decision to another proceeding. The AD also notes that the ICIP for Diablo Canyon would continue until the Utility has recovered its transition costs, and implies that ICIP is tied to recovery of transition costs. The AD also proposes a cost-based 2002 retained generation revenue requirement for the Utility of $2,875 million although it is not clear which costs would be subject to future adjustments.

In January 2001, the California Legislature passed AB 6X, which amended Public Utilities Code (PUC) Section 377 to prohibit utilities from divesting their retained generating plants before January 1, 2006. AB 6X did not amend PUC Section 367, which requires the CPUC to market value the generating assets of each utility by no later than December 31, 2001, based on appraisal, sale, or other divestiture. However, on December 21, 2001, a CPUC Commissioner issued a ruling indicating that in her opinion AB 6X supersedes PUC Section 367 to delete any requirement of market valuation for utility generation assets. On January 15, 2002, the Utility filed comments reiterating the reasons contained in previous pleadings as to why the enactment of AB 6X did not supersede or repeal the CPUC's statutory obligation to market value the Utility's generation assets by December 31, 2001.

On January 17, 2002, the Utility filed an administrative claim with the State of California Victim Compensation and Government Claims Board (Board) alleging that the January 2001 enactment of AB 6X violates the Utility's contractual rights under AB 1890. The Utility's claim seeks compensation for the denial of the Utility's right to at least $4.1 billion market value of its retained generating facilities in FERC-regulated interstate power markets. On February 22, 2002, the Board denied the Utility's claim. The Utility has six months from the date of the denial to file suit on this claim in California Superior Court.

The Utility cannot predict what the outcome of any of these proceedings will be or whether they will have a material adverse effect on its results of operations or financial condition.

The CPUC established the Revenue Adjustment Proceeding (RAP) to verify amounts recorded in the Utility's Transition Revenue Account (TRA) and to verify authorized revenue requirements, including adjustments approved in other proceedings. The RAP also establishes revenue allocation and rate design, and identifies all electric balancing and memorandum accounts for continued retention or elimination.

In June 2001, the Utility filed its RAP application addressing revenues and costs recorded in the TRA from July 1, 1999, through April 30, 2001. A CPUC decision and related appeals are still pending.

The Annual Transition Cost Proceeding (ATCP) was established to verify the accounting and recording of costs and revenues in the Transition Cost Balancing Account (TCBA), and ensure that only eligible transition costs have been entered. The TCBA tracks the revenues available to offset transition costs, including the accelerated recovery of plant balances, and other generation-related assets and obligations. Transition costs will receive a limited "reasonableness" review.

In September 2000, the Utility filed its 2000 ATCP application seeking approval of amounts recorded in the TCBA and generation memorandum accounts for the period July 1, 1999, through June 30, 2000. The CPUC has

not yet issued a decision covering that period. In September 2001, the Utility filed its 2001 ATCP application seeking approval of the recorded amounts for the period July 1, 2000, through June 30, 2001.

On January 19, 2001, the Utility was no longer able to continue purchasing power for its customers because of lack of creditworthiness, and as a result, the State of California authorized the DWR to purchase electricity for the Utility's customers. The ISO continued to bill the Utility for its power purchase costs that were incurred to cover the Utility's net open position not covered by the DWR. On February 14, 2001, the FERC ordered that the ISO could buy power only on behalf of creditworthy entities. On April 6, 2001, the FERC issued a further order directing the ISO to implement its prior order, which, the FERC clarified, applies to all third-party transactions whether scheduled or not. On June 13, 2001, the FERC denied the ISO's request for rehearing of its April 6, 2001, order.

The Utility has not recorded any estimated ISO charges after April 6, 2001, except for the ISO's grid management charge, although the Utility has accrued the full amount of the ISO charges of approximately $1 billion up to April 6, 2001.

On November 7, 2001, the FERC issued an order granting a motion by a group of generators to enforce the creditworthiness requirements of the ISO tariff and rejecting an amendment proposed by the ISO. The FERC noted that its prior February 14 and April 6, 2001, orders required a creditworthy counterparty for power purchases. The FERC stated that the ISO is obligated to invoice, collect payments from, and distribute payments to the DWR for all scheduled and unscheduled transactions on behalf of the DWR, including transactions where the DWR serves as the creditworthy counterparty for the applicable portion of the Utility's load. The November 7, 2001, order directs the ISO to (1) enforce its billing and settlement provisions under the ISO tariff, (2) invoice the DWR for all ISO transactions it entered into on behalf of the Utility and Southern California Edison within 15 days from the date of the order, with a schedule for payment of overdue amounts within three months, and (3) reinstate the billing and settlement provisions under the tariff.

Subsequently, the ISO has issued invoices to the DWR for the amounts in dispute. The DWR is in the process of paying substantially all such invoices for the period from January 17, 2001, forward. On December 7, 2001, the DWR filed an application for rehearing of the FERC order, alleging, among other things, that the FERC order was illegal and unconstitutional because it restricted the DWR's unilateral discretion to determine the prices it would pay for third party power under the ISO invoices. If the FERC upholds its previous ruling that the DWR, not the Utility, is responsible for amounts billed by the ISO to the DWR for the period from January 17, 2001, through April 6, 2001, the Utility will reverse the $1 billion accrued during 2001. However, if the Utility reverses the ISO accrual, it would need to record an accrual for its obligations to the DWR for such purchases. The Utility expects that this DWR accrual would not exceed the ISO reversal.

The FERC issued a series of significant orders in the spring and summer of 2001 that prescribed prospective price mitigation relief. On April 26, 2001, the FERC issued an order that prescribed price mitigation for those hours in which the ISO declared an emergency. The order also imposed a requirement that all generators in California offer available generation for sale to the ISO's real-time energy market during all hours. While the Utility recognized the importance of the FERC's action, it sought rehearing of the April 26, 2001, order on the premise that the price mitigation methodology could be made more comprehensive, both in terms of the hours in which it was to be applied and the types of transactions that it covered.

In June 2001, the FERC further ordered prospective price mitigation for the wholesale spot markets throughout both California and the Western Systems Coordinating Council (WSCC) that established the current mitigation methodology going forward. Features of this current methodology include:

In June and July 2001, the FERC's chief ALJ conducted settlement negotiations among power generators, the State of California, and the California investor-owned utilities, in an attempt to resolve disputes regarding past power sales. The State represented that it and the California investor-owned utilities are owed $8.9 billion for electricity overcharges by the generators. The negotiations did not result in a settlement, but the judge recommended that the FERC conduct further hearings to determine what the power sellers and buyers are each owed. The Utility does not believe these matters will be resolved until mid- to late 2002, nor can it predict

whether a refund will be ordered or the amount the Utility might receive. In connection with this proceeding, on August 17, 2001, the ISO submitted data indicating that a PG&E NEG affiliate, PG&E Energy Trading- Power, L.P. (ET Power) may be required to refund approximately $26 million. However, the FERC has indicated that unpaid amounts owed by the ISO and the PX may be used as offsets to any refund obligations. Potential offsets would significantly reduce any potential refund required to be made by ET Power. Finalization of any refunds and offsets are subject to the on-going FERC proceeding.

Until September 20, 2001, California's restructured electricity market gave customers the option of subscribing either to "bundled service" from the Utility or "direct access" service from an ESP. Direct access customers receive distribution and transmission service from the Utility, but purchase electricity (generation) from their ESP. Customers receiving bundled services receive distribution, transmission, and generation services from the Utility. On September 20, 2001, the CPUC, pursuant to AB 1X, suspended the right of retail end-use customers to acquire direct access service thereby preventing additional customers from entering into contracts to purchase electricity from outside service providers. The decision did not address agreements entered into before September 29, 2001, including renewals of such contracts or agreements, and stated that such issues would be addressed in a subsequent decision. On January 25, 2002, the CPUC issued a proposed decision that, if made final, will suspend direct access retroactive to July 1, 2001. In addition to making void all direct access contracts entered into on or after July 1, 2002, the proposed decision prevents customers with valid direct access contracts entered into prior to this date from switching service providers, adding locations, or renewing the terms of such contracts. An alternate proposed decision maintains the original direct access suspension date of September 20, 2001. The comment period for the proposed decision expired February 14, 2002.

The Utility's ability to recover incurred generation costs is affected by the amount of generation-related revenues the Utility is able to collect. To the extent that the Utility's customers elect direct access service, they do not pay generation-related revenue to the Utility. Direct access credits totaled $461 million in 2001. See the "Results of Operations—Electric Revenue" section for a discussion of direct access credits.

Each year, the Utility files an application with the CPUC to determine the authorized rate of return that the Utility may earn on its electric and gas distribution assets and recover from ratepayers. Since February 17, 2000, the Utility's adopted return on common equity (ROE) has been 11.22 percent on electric and gas distribution operations, resulting in an authorized 9.12 percent overall rate of return (ROR). The Utility's earlier adopted ROE was 10.6 percent. In May 2000, the Utility filed an application with the CPUC to establish its authorized ROR for electric and gas distribution operations for 2001. The application requests a ROE of 12.4 percent and an overall ROR of 9.75 percent. If granted, the requested ROR would increase 2001 electric and gas distribution revenues by approximately $72 million and $23 million, respectively. The application also requests authority to implement an Annual Cost of Capital Adjustment Mechanism for 2002 through 2006 that would replace the annual cost of capital proceedings. The proposed adjustment mechanism would modify the Utility's cost of capital based on changes in an interest rate index. The Utility also proposes to maintain its currently authorized capital structure of 46.2 percent long-term debt, 5.8 percent preferred stock, and 48 percent common equity. In March 2001, the CPUC issued a proposed decision recommending no change to the current 11.22 percent ROE for test year 2001. A final CPUC decision is pending.

Electric transmission revenues and both wholesale and retail transmission rates are subject to authorization by the FERC. The FERC has not yet acted upon a settlement filed by the Utility that, if approved, would allow the Utility to recover $391 million in electric transmission rates for the 14-month period of April 1, 1998, through May 31, 1999. During this period, somewhat higher rates have been collected, subject to refund. A FERC order approving this settlement is expected by the end of 2002. The Utility has accrued $29 million for potential refunds related to the 14-month period ended May 31, 1999.

In July 2001, the FERC approved a settlement that permits the Utility to collect $262 million annually, (net of the 2002 Transmission Revenue Balancing Account) in electric transmission rates beginning on May 6, 2001. This decrease in transmission rates relative to previous time periods is due to unusually large balances paid to the Utility by the ISO for congestion management charges and other transmission-related services billed by the ISO

that are booked in the Transmission Revenue Balancing Account. These balances paid by the ISO are offset against the Utility's transmission revenue requirement. The Utility does not expect the outcome of these settlements to have a material adverse effect on its results of operations or financial condition.

In March 2001, the Utility filed at the FERC to increase its power and transmission-related rates to the Western Area Power Administration (WAPA). The majority of the requested increase is related to passing through market power prices billed to the Utility by the ISO and others for services, which apply to WAPA under a pre-existing contract between the Utility and WAPA. On September 21, 2001, the FERC ALJ issued an Initial Decision denying the Utility the ability to increase the rates as requested. On October 24, 2001, the FERC confirmed the ALJ's Initial Decision in its entirety. The FERC denied the Utility's November 21, 2001, request for rehearing, and that decision has been appealed to the U.S. Court of Appeals for the D.C. Circuit. Pending a decision from the Court, until December 31, 2004, the date the WAPA contract expires, WAPA's rates will continue to be calculated on a yearly basis pursuant to the formula specified in WAPA's contract under AB 1890. Any revenue shortfall or benefit resulting from this contract is included in rates through the end of the contract period as a purchased power cost.

In connection with electric industry restructuring, the ISO was established to provide operational control over most of the state's electric transmission facilities and to provide comparable open access for electric transmission service. The Utility serves as the scheduling coordinator to schedule transmission with the ISO to facilitate continuing service under existing wholesale transmission contracts that the Utility entered into before the ISO was established. The ISO bills the Utility for providing certain services associated with these contracts. These ISO charges are referred to as the "scheduling coordinator (SC) costs."

As part of the Utility's Transmission Owner rate case filed at the FERC, the Utility established the Transmission Revenue Balancing Account (TRBA) to record these SC costs in order to recover these costs through transmission rates. Certain transmission-related revenues collected by the ISO and paid to the Utility are also recorded in the TRBA. Through December 31, 2001, the Utility had recorded approximately $110 million of these SC costs in the TRBA. (The Utility has also disputed approximately $27 million of these costs as incorrectly billed by the ISO. Any refunds that ultimately may be made by the ISO would be credited to the TRBA.)

In September 1999, an ALJ of the FERC issued a proposed decision denying recovery of these SC costs from retail and new wholesale customers in the TRBA. The ALJ indicated that the Utility should try to recover these costs from existing wholesale customers. The proposed decision is subject to change by the FERC in its final decision. The FERC is expected to issue a final decision in 2002. In January 2000, the FERC accepted a proposal by the Utility to establish the Scheduling Coordinator Services (SCS) Tariff. The SCS Tariff would serve as a back-up mechanism for recovery of the SC costs from existing wholesale customers if the FERC ultimately decides that these costs may not be recovered in the TRBA. The FERC also conditionally granted the Utility's request that the SCS Tariff be effective retroactive to March 31, 1998. However, the FERC suspended the procedural schedule until the final decision is issued regarding the inclusion of SC costs in the TRBA.

The Utility does not expect the outcome of this proceeding to have a material adverse effect on its results of operations or financial condition.

Under a ratemaking pact called the Gas Accord, implemented in March 1998, the Utility's gas transmission services were separated or unbundled from its distribution services, and the terms of service and rate structure for gas transportation were changed. The Gas Accord also allows core customers to purchase gas from competing suppliers, establishes an incentive mechanism to measure the reasonableness of core procurement costs, and establishes gas transmission and storage rates through 2002. On October 9, 2001, the Utility filed a Gas Accord II application with the CPUC, requesting a two-year extension, without modification to the terms and conditions of the existing Gas Accord. In return, the Utility will forego its ability under the original Gas Accord to increase rates 2.5 percent annually during the extended time period.

Under the Utility's proposal, those provisions of the Gas Accord currently scheduled to expire on January 1, 2003, will be extended through December 31, 2004, while certain storage-related provisions scheduled to expire on April 1, 2003, will be extended through March 31, 2005. No change is proposed to the previously approved rates in effect as of December 2002 or, in the case of certain storage provisions, as of March 31, 2003. The Utility believes the two-year extension that has been proposed will allow for resolution of many uncertainties affecting

gas markets today, including the Utility's proposed plan of reorganization. The CPUC has not issued a decision in this proceeding. The Utility cannot predict what the outcome of the decision will be, or whether the outcome will have a material adverse effect on its results of operations or financial condition.

On November 8, 2000, the Utility filed a lawsuit in federal District Court in San Francisco against the CPUC Commissioners. The Utility asked the District Court to declare that the federally approved wholesale electricity costs that the Utility has incurred to serve its customers are recoverable in retail rates both before and after the end of the transition period. The lawsuit stated that the wholesale power costs that the Utility has incurred are paid pursuant to filed tariffs, which the FERC has authorized and approved, and that under the United States Constitution and numerous federal court decisions, state regulators cannot disallow such costs. The Utility's lawsuit also alleged that to the extent the Utility is denied recovery of these mandated wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility's property.

On May 2, 2001, the District Court dismissed the Utility's complaint, without prejudice to refile the lawsuit at a later time, on the ground that the suit was premature since two of the challenged CPUC decisions were not yet final. On August 6, 2001, the Utility refiled its complaint in the U.S. District Court for the Northern District of California, based on the fact that the CPUC's decisions referenced in the District Court's order had become final under California law. The CPUC and TURN have filed motions to dismiss the complaint. On November 26, 2001, the case was transferred to a District Court in the Northern District of California and consolidated as a related case with the Utility's appeal of the Bankruptcy Court's denial of the Utility's request for injunctive and declaratory relief against the retroactive accounting order adopted by the CPUC in March 2001. A case management conference in both actions is scheduled for March 7, 2002.

Order Instituting Investigation (OII) into Holding Company Activities and Related Litigation

On April 3, 2001, the CPUC issued an OII into whether the California investor-owned utilities, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate (1) the utilities' transfer of money to their holding companies since deregulation of the electric industry commenced, including during times when their utility subsidiaries were experiencing financial difficulties, (2) the failure of the holding companies to financially assist the utilities when needed, (3) the transfer by the holding companies of assets to unregulated subsidiaries, and (4) the holding companies' action to "ringfence" their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate.

On January 9, 2002, the CPUC issued an interim decision interpreting the "first priority condition" adopted in the CPUC's holding company decisions (the condition that the capital requirements of the utility, as determined to be necessary and prudent to meet the utility's obligation to serve or operate the utility in a prudent and efficient manner, be given first priority by the board of directors of the holding company). In the interim decision, the CPUC concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration, and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility's ability to fulfill its obligation to serve or to operate in a prudent and efficient manner.

In a related decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision mailed on January 11, 2002, the CPUC stated that PG&E Corporation was being dismissed so

that an appropriate legal forum could decide expeditiously whether adoption of the Utility's proposed plan of reorganization would violate the first priority condition.

On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, alleging PG&E Corporation violated various conditions established by the CPUC and engaged in other unfair or fraudulent business practices or acts. The Attorney General also alleges that the December 2000 and January and February 2001 ringfencing transactions by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions.

In a press release issued on January 10, 2002, the CPUC expressed support for the Attorney General's complaint, noting that the CPUC's January 9, 2002, decision provided a basis for the Attorney General's allegations and that the CPUC intends to join in a lawsuit against PG&E Corporation based on these issues.

Among other allegations, the Attorney General alleges that, through the Utility's bankruptcy proceedings, PG&E Corporation and the Utility engaged in unlawful, unfair and fraudulent business practices by seeking to implement the transactions proposed in the proposed plan of reorganization filed in the Utility's bankruptcy proceeding. The complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. The Bankruptcy Court has original and exclusive jurisdiction of these claims. Therefore, on February 8, 2002, PG&E Corporation filed a notice of removal in the Bankruptcy Court to transfer the Attorney General's complaint to the Bankruptcy Court. On February 15, 2002, a motion to dismiss the lawsuit or in the alternative to stay the suit, was filed.

On February 11, 2002, a complaint entitled, City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the Attorney General's complaint including allegations of unfair competition. In addition, the complaint alleges causes of action for (1) conversion, claiming that PG&E Corporation "took at least $5.2 billion from the Utility," and (2) "unjust enrichment."

The complaint seeks injunctive relief, the appointment of a receiver, restitution, disgorgement, the imposition of a constructive trust, civil penalties, and costs of suit.

PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor PG&E Corporation, however, can predict what the outcome of the CPUC's investigation will be or whether the outcome will have a material adverse effect on their results of operations or financial condition. PG&E Corporation will vigorously respond to and defend the litigation.

The statutory end of the transition period is March 31, 2002. In September 2001, California Senate Bill (SB) X2 was passed which prohibits the CPUC from raising rates for residential and small commercial customers solely as a result of the statutory end of the rate freeze. In conjunction with the end of the transition period, the Utility will discontinue deferring generation-related costs associated with its 10 percent rate reduction provided to certain customers. During the transition period, the Utility provided the 10 percent rate reduction by financing a portion of its generation-related costs with Rate Reduction Bonds (see Note 10 for a description of Rate Reduction Bonds). In accordance with AB 1890, these financed generation-related transition costs were deferred to the Rate Reduction Bond regulatory asset. The Rate Reduction Bond regulatory asset will be recovered after the end of the transition period through fixed transition revenues. Also, in the first quarter of 2002, the Utility will begin amortizing its Rate Reduction Bond regulatory asset. This amortization will be approximately $290 million per year and will be offset against fixed transition revenues. In 2001, fixed transition revenues were included in the generation component of electric rates and contributed to the excess of generation-related revenues over generation-related costs.

The Utility administers general and low income energy efficiency programs funded through a public goods component in customers' rates. The Utility receives incentives for this activity, including incentives based on a portion of the net present value of the savings achieved by the programs, incentives based on accomplishing certain tasks, and incentives based on expenditures. Annually, the Utility files an earnings claim in the AEAP, a forum for stakeholders to comment on and for the CPUC to evaluate the Utility's claim verification.

In May 2000, PG&E filed its 2000 AEAP application, which establishes incentives to be collected during 2001. The CPUC has delayed action on the Utility's 2000 AEAP and joined the 2000 AEAP with the Utility's 2001 AEAP. The third pre-hearing conference for the joint proceeding is scheduled for February 2002. The Utility claim for shareholder incentives in this combined proceeding is approximately $80 million. The Utility has not reflected incentives in the Utility's Consolidated Statements of Operations for the year ended December 31, 2001.

In the 1999 AEAP, which established incentives to be collected in 2000, the CPUC authorized incentives of approximately $26 million. These incentives are reflected in the Utility's Consolidated Statements of Operations for the year ended December 31, 2000.

The Utility expects to file with the CPUC its 2002 AEAP application in May 2002.

PG&E Corporation and the Utility are subject to laws and regulations established to both maintain and improve the quality of the environment. Where PG&E Corporation's and the Utility's properties contain hazardous substances, these laws and regulations require PG&E Corporation and the Utility to remove those substances or remedy effects on the environment. See Note 16 of the Notes to the Consolidated Financial Statements for further discussion of environmental matters.

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, 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 or disposal of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances, even if it did not deposit those substances on the site.

The Utility records an environmental remediation liability when site assessments indicate remediation is probable and a range of reasonably likely clean-up costs can be estimated. The Utility reviews its remediation liability quarterly for each identified site. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring, and site closure using (1) current technology, (2) enacted laws and regulations, (3) experience gained at similar sites, and (4) 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 lower end of this range.

The Utility had an environmental remediation liability of $295 million and $320 million at December 31, 2001, and 2000, respectively. The $295 million accrued at December 31, 2001, includes (1) $139 million related to the pre-closing remediation liability, associated with divested generation facilities, and (2) $156 million related to remediation costs for those generation facilities that the Utility still owns, manufactured gas plant sites, and gas gathering compressor stations. Of the $295 million environmental remediation liability, the Utility has recovered $193 million through rates, and expects to recover the balance in future rates. The Utility also is recovering its costs from insurance carriers and from other third parties as appropriate.

On June 28, 2001, the Bankruptcy Court authorized the Utility to continue its hazardous waste remediation program and to expend:

At December 31, 2001, the Utility estimates total future costs for hazardous waste remediation at identified sites, including divested fossil-fueled power plants to be $295 million (undiscounted). The cost of the hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. A change in the estimate 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. If other potentially responsible parties are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated, the Utility's future cost could increase by as much as $446 million. The Utility estimates the upper limit of the range using assumptions least favorable to the Utility, based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for clean-up costs at additional sites or expected outcomes change.

The California Attorney General, on behalf of various state environmental agencies, filed claims in the Utility's bankruptcy proceeding for environmental remediation at numerous sites aggregating to approximately $770 million. For most if not all of these sites, the Utility is in the process of remediation in cooperation with the relevant agencies or would be doing so in the future in the normal course of business. In addition, for the majority of the remediation claims, the state would not be entitled to recover these costs unless they accept responsibility to clean up the sites, which is unlikely. Since the proposed plan of reorganization provides that the Utility intends to respond to these types of claims in the regular course of business, and since the Utility has not argued that the bankruptcy proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the claims seeking specific cash recoveries are invalid.

In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had violated the plant's National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). A claim has been filed by the California Attorney General in the Utility's bankruptcy proceeding on behalf of the Central Coast Board seeking unspecified penalties.

The Utility's Diablo Canyon generating facility employs a "once through" cooling water system, which is regulated under a NPDES permit issued by the Central Coast Board. This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft Cease and Desist Order alleging that, although the temperature limit has never been exceeded, Diablo Canyon's discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology reflects the "best technology available" under Section 316(b) of the Federal Clean Water Act. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment and will be incorporated in a consent decree to be entered in California Superior Court. A claim has been filed by the California Attorney General in the Utility's bankruptcy proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with Diablo Canyon's operation of its cooling water system.

The Utility believes the ultimate outcome of these matters will not have a material impact on its financial position or results of operations.

PG&E NEG anticipates spending up to approximately $337 million, net of insurance proceeds from 2002, through 2008 for environmental compliance at currently operating facilities. To date, PG&E NEG has spent approximately $8 million of this amount. PG&E NEG believes that a substantial portion of this amount will be funded from its operating cash flow. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG.

In May 2000, PG&E NEG received an Information Request from the U.S. Environmental Protection Agency (EPA), pursuant to Section 114 of the Federal Clean Air Act (CAA). The Information Request asked PG&E NEG to provide certain information relative to the compliance of the Brayton Point and Salem Harbor Generating Stations with the CAA. No enforcement action has been brought by the EPA to date. PG&E NEG has had very preliminary discussions with the EPA to explore a potential settlement of this matter. As a result of this and related regulatory initiatives by the Commonwealth of Massachusetts, PG&E NEG is exploring initiatives that would assist it to achieve significant reductions of sulfur dioxide, nitrogen oxide, and thermal emissions by 2006. PG&E NEG believes that it would meet these requirements through installation of controls at the Brayton Point and Salem

Harbor plants and estimates that capital expenditures on these environmental projects will be approximately $266 million over the next five years. PG&E NEG believes that it is not possible to predict at this point whether any such settlement will occur or, in the absence of a settlement, the likelihood of whether the EPA will bring an enforcement action.

PG&E Gen's existing power plants, including USGen New England, Inc. (USGenNE) facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and it is anticipated that all three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. It is estimated that USGenNE's cost to comply with the new permit conditions could be as much as $67 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits.

In September 2000, USGenNE signed a series of agreements that require it to alter its existing wastewater treatment facilities at the Brayton Point and Salem Harbor generating facilities. Through December 31, 2001, USGenNE has incurred approximately $8 million and expects that total costs will be approximately $18 million. Certain of these costs have been capitalized and a receivable has been recorded for amounts it believes are probable of recovery through insurance proceeds.

Financial statements, which are prepared in accordance with accounting principles generally accepted in the United States of America, report operating results in terms of historical costs and do not evaluate the impact of inflation. Inflation affects our construction costs, operating expenses, and interest charges. In addition, the Utility's electric revenues do not reflect the impact of inflation due to the current electric rate freeze. However, inflation at current levels is not expected to have a material adverse impact on PG&E Corporation's or the Utility's financial position or results of operations.

PG&E Corporation and the Utility have established risk management policies that allow the use of energy, financial, and weather derivative instruments (a derivative is a contract whose value is dependent on or derived from the value of some underlying asset) and other instruments and agreements to be used to manage its exposure to market, credit, volumetric, regulatory, and operational risks. PG&E Corporation and the Utility use derivatives for both trading (for profit) and non-trading (hedging) purposes. Trading activities may be done for purposes of gathering market intelligence, creating liquidity, maintaining a market presence, and taking a market view. Non-trading activities may be done for purposes of mitigating the risks associated with an asset (natural position embedded in asset ownership and regulatory requirements), liability, committed transaction, or probable forecasted transaction. Such derivatives include forward contracts, futures, swaps, options, and other contracts.

PG&E Corporation and the Utility may engage in the trading of derivatives only in accordance with policies set forth by the PG&E Corporation Risk Policy Committee. Trading is permitted only after PG&E Corporation's Risk Policy Committee approves appropriate limits for such activity and the organizational unit proposing this activity successfully demonstrates that there is a business need for such activity and that the market risks will be adequately measured, monitored, and controlled. PG&E Corporation's Risk Policy Committee is responsible for the overall approval of the Risk Management Policy and the delegation of approval and authorization levels. The Risk Policy Committee is comprised of senior executives who receive updates on market conditions, risk positions, credit exposures and overall results. Under PG&E Corporation, both PG&E NEG and the Utility have their own Risk Management Committees that address matters relating to those companies' respective businesses. These Risk Management Committees are also comprised of senior officers.

PG&E Corporation applies mark-to-market accounting to all of its trading activities, under the guidance in Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for Contracts Involving Energy Trading and Risk Management Activities," which are recorded at fair value with realized and unrealized gains (losses) in earnings. The recognized but unrealized balances are recorded on the Consolidated Balance Sheets as price risk management assets and liabilities. Non-trading contracts that meet the definition of a derivative under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," may be classified as normal purchases and sales or cash flow hedges. Those derivatives that qualify for normal purchases and sales treatment are exempt

from the fair value requirements of SFAS No. 133. Derivatives that are designated and qualify for cash flow hedge treatment are tested for their effectiveness in hedging the underlying position. Gains or losses associated with the hedge effectiveness are recorded on the Consolidated Balance Sheets in Other Comprehensive Income (OCI) and are reclassified into earnings in the period in which the underlying transaction affects earnings. Gains and losses associated with the ineffective portion of such hedges are recognized in earnings immediately. PG&E Corporation, through PG&E NEG, participates in trading and non-trading activities; the Utility participates only in non-trading activities.

The activities affecting the estimated fair value of trading activities, are presented below:

Fair values of trading contracts at January 1, 2001	$	199
Net gain on contracts settled during the period		(296	)
Fair value of new trading contracts when entered into		—
Changes in fair values attributable to changes in valuation techniques and assumptions		—
Other changes in fair values		130

Fair values of trading contracts outstanding at December 31, 2001		33
Fair value of non-trading contracts		63

Net price risk management assets at December 31, 2001	$	96

PG&E Corporation estimated the gross mark-to-market value of its trading contracts as of December 31, 2001, using the mid-point of quoted bid and ask prices, where available, and other valuation techniques when market data was not available (e.g. illiquid markets or products). In such instances, PG&E Corporation utilizes alternative pricing methodologies, including, but not limited to, third party pricing curves, the extrapolation of forward pricing curves using historically reported data or interpolating between existing data points. Most of PG&E Corporation's risk management models are reviewed by or purchased from third party experts with extensive experience in specific derivative applications. Fair value contemplates the effects of credit risk, liquidity risk, and time value of money on gross mark-to-market positions through the application of reserves.

The following table shows the sources of prices used to calculate the fair value of trading contracts at December 31, 2001. In many cases, these prices are fed into option models that calculate a gross mark-to-market value from which fair value is derived after considering reserves for liquidity, credit, time value, and model confidence.

The amounts disclosed above are not indicative of likely future cash flows, as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity, and PG&E Corporation's risk management portfolio needs and strategies.

To the extent that PG&E Corporation and the Utility have an open position (an open position is a position that is either not hedged or only partially hedged), it is exposed to the risk that fluctuations in commodity, futures and basis prices may impact financial results. Such risks include any and all change in value whether caused by trading positions, asset ownership/availability, debt covenants, exposure concentration, currency, weather, etc. regardless of accounting method. Market risk is also affected by changes in volatility, correlation and liquidity. We manage our exposure to market fluctuations within the risk limits provided for in the PG&E Corporation Risk Management Policy and minimize forward value fluctuations through hedging (i.e., selling plant output, buying fuel, utilizing transportation and transmission capacity) and portfolio management.

Commodity price risk is the risk that changes in market prices of a commodity for physical delivery will adversely affect earnings and cash flows.

In compliance with regulatory requirements, the Utility manages commodity price risk independently from the activities in PG&E Corporation's unregulated businesses. Because of different regulatory incentives and ratemaking methods, the Utility reports its commodity price risk separately for its electricity and natural gas businesses. Price risk management strategies consist primarily of the use of physical forward purchases and non-trading financial instruments to attain our objective of reducing the impact of commodity price fluctuations for electricity and natural gas associated with the Utility's procurement obligations to meet its retail electricity and natural gas loads. While the use of these instruments has been authorized by the CPUC, the CPUC has yet to establish rules around how it will judge the reasonableness of these instruments for electricity purchases. Gains and losses associated with the use of the majority of these financial instruments primarily affect regulatory accounts, depending on the business unit and the specific program involved.

The Utility has had a very limited ability to enter into forward contracts to hedge its exposure to commodity price fluctuations because of the reluctance of counterparties to extend credit. As the Utility's credit rating dropped below investment grade in January 2001, the DWR began purchasing wholesale power for electric customers on behalf of the state of California. The Utility is currently paying the DWR the amount of money it collects in retail generation rates for electricity purchased by the DWR for the net open position. The Utility believes that it is obligated to remit only these revenues to the DWR and, therefore, there is no price risk for electricity purchases to serve the net open position.

As explained in Note 2 of the Notes to the Consolidated Financial Statements, on September 20, 2001, PG&E Corporation and the Utility filed a proposed plan of reorganization of the Utility with the Bankruptcy Court. Upon the effective date of the Plan, the reorganized Utility will transfer its generation assets to Gen. Gen will operate as an independent power producer thereafter. As an independent owner/operator, Gen could face increased price risk associated with variability in power prices. Additionally, the reorganized Utility could face price risk if and when it resumes the net open position not already provided for by the DWR's contracts. The Plan proposes that the Reorganized Utility may reassume this responsibility at an unknown future date when certain specified conditions are met, including receiving an investment grade credit rating. To manage electric commodity price risk for both companies and to provide a sufficiently stable framework for financing, Gen proposes to sell its generation output to the reorganized Utility under a power sales agreement having a term of 12 years. As a result, during the term of the agreement, the price risk should be limited to replacement power requirements, if any, brought about by low hydroelectric availability and/or unit outages that may occur.

Under a ratemaking method called the Core Procurement Incentive Mechanism (CPIM), the Utility recovers in retail rates the cost of procuring natural gas for its customers as long as the costs are within a 99 percent to 102 percent "dead-band" of a benchmark price. The CPIM benchmark price reflects a weighting of prescribed daily and monthly gas price indices that are representative of Utility gas purchases. Ratepayers and shareholders share costs or savings outside the "dead-band" equally. In addition, the Utility has contracts for capacity on various gas pipelines. There is price risk related to the Transwestern gas pipeline to the extent that unused portions of the pipeline are brokered at floating rates.

Under a ratemaking pact called the Gas Accord, currently scheduled to be in effect through December 2002, shareholders are at risk for any revenues from the sale of capacity on the Utility's pipelines and gas storage fields held by the California Gas Transmission (CGT) business unit. According to the terms of the Gas Accord, a portion of the pipeline and storage capacity is sold at competitive market-based rates. The Utility is generally exposed to reduced revenues when the price spreads between two delivery points narrow. In addition, the Utility is generally exposed to reduced revenues when throughput volumes are lower than expected, primarily caused by temperature and precipitation effects or by economy-driven impacts. On October 9, 2001, the Utility filed another Gas Accord application with the CPUC requesting a two-year extension without modification to existing terms and conditions of the existing Gas Accord. In return, the Utility will forego its ability to increase rates 2.5 percent annually during the extended time period. It is unclear when the CPUC will act upon the Utility's proposal.

PG&E NEG is exposed to commodity price risk of its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, in addition to various merchant plants currently in development. PG&E NEG manages such risks using a cost-effective risk management program that primarily includes the buying and selling of fixed-price commodity commitments to lock in future cash flows of their forecasted generation. PG&E NEG is also exposed to commodity price risk of net open positions within their trading portfolio due to the assessment of and response to changing market conditions.

PG&E Corporation and the Utility measure commodity price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future potential losses. Market risk is quantified using a variance/co-variance value-at-risk model that provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period.

PG&E Corporation uses historical data for calculating the price volatility of its contractual positions and how likely the prices of those positions will move together. The model includes all derivatives and commodity instruments in the trading and non-trading portfolios. PG&E Corporation and the Utility express value-at-risk as a dollar amount of the potential loss in the fair value of their portfolios based on a 95 percent confidence level using a one-day liquidation period. Therefore, there is a 5 percent probability that PG&E Corporation and its subsidiaries' portfolios will incur a loss in one day greater than its value-at-risk. For example, if the value-at-risk is calculated at $5 million, there is a 95 percent confidence level that if prices moved against current positions, the reduction in the value of the portfolio resulting from such one-day price movements would not exceed $5 million.

The following table illustrates the daily value-at-risk exposure for commodity price risk.

*Includes the Utility's gas portfolio only. The Utility believes that there is currently no commodity price risk associated with fluctuating electric power prices, because the Utility is not currently responsible for managing the net open position.

**Includes only the risk related to the financial instruments that serve as hedges and does not include the related underlying hedged item.

***Portfolio VAR includes a rolling three year position reflecting the underlying position associated with PG&E NEG's owned assets, the full tenor of PG&E NEG's asset hedges, and trading positions.

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, 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. Value-at-risk also does not reflect the significant regulatory, legislative, and legal risks currently facing the Utility due to the Utility's bankruptcy proceedings and the current California energy crisis.

Interest rate risk is the risk that changes in interest rates could adversely affect earnings and cash flows. Specific interest rate risks for PG&E Corporation and the Utility include the risk of increasing interest rates on short-term and long-term floating rate debt, the risk of decreasing rates on floating rate assets which have been financed with fixed rate debt, the risk of increasing interest rates for planned new fixed long-term financings, and

the risk of increasing interest rates for planned refinancing using long-term fixed rate debt. In addition, the Utility is exposed to changes in interest rates on interest accruing on loan payments and trade payables currently in default.

PG&E Corporation uses the following interest rate instruments to manage its interest rate exposure: interest rate swaps, interest rate caps, floors, or collars, swaptions, or interest rate forward and futures contracts. Interest rate risk sensitivity analysis is used to measure interest rate price risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. If interest rates change by 1 percent for all variable rate debt at PG&E Corporation and the Utility, the change would affect net income by approximately $32.5 million and $26.4 million, respectively, based on variable rate debt and derivatives and other interest rate sensitive instruments outstanding at December 31, 2001.

Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. The Utility and PG&E Corporation are exposed to foreign currency risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements. In addition, PG&E Corporation has translation exposure resulting from the need to translate Canadian-denominated financial statements of its affiliate PG&E Energy Trading Canada Corporation into U.S. dollars for PG&E NEG Consolidated Financial Statements. PG&E Corporation and the Utility use forwards, swaps, and options to hedge foreign currency exposure.

PG&E Corporation and the Utility use sensitivity analysis to measure their foreign currency exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at December 31, 2001, a 10 percent devaluation of the Canadian dollar would be immaterial to PG&E Corporation's and the Utility's Consolidated Financial Statements.

Credit risk is the risk of loss that PG&E Corporation and the Utility would incur if counterparties fail to perform their contractual obligations. PG&E Corporation and the Utility primarily conduct business with customers in the energy industry, and this concentration of counterparties may impact the overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory, or other conditions. PG&E Corporation and the Utility manage credit risk pursuant to its Risk Management Policies, which provide processes by which counterparties are assigned credit limits in advance of entering into significant exposure. These procedures include an evaluation of a potential counterparty's financial condition, net worth, credit rating, and other credit criteria as deemed appropriate and are performed at least annually. Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E Corporation and the Utility take immediate action to reduce exposure and/or obtain additional collateral. Further, PG&E Corporation and the Utility rely heavily on master agreements that allow for the netting of positive and negative exposures associated with a counterparty. No single counterparty represents greater than 10 percent of PG&E Corporation's total gross credit exposure at December 31, 2001. The fair value of all claims against these counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange guarantees that every contract is properly settled on a daily basis), as of December 31, 2001, amount to the following:

The majority of counterparties to which PG&E Corporation and the Utility are exposed are considered to be of investment grade, determined using publicly available information including an S&P's rating of at least BBB-.

$296 million or 25 percent of PG&E Corporation's gross credit exposure and $59 million or 22 percent of the Utility's gross credit exposure is below investment grade. PG&E Corporation has regional concentrations of credit exposure to counterparties that primarily conduct business throughout the western United States (30 percent) and also to counterparties that primarily conduct business throughout the entire United States (51 percent). The Utility has a regional concentration of credit exposure to counterparties that primarily conduct business throughout the entire United States (93 percent).

In accordance with various agreements, the Utility and other subsidiaries provide and receive various services from their parent, PG&E Corporation. The Utility and PG&E Corporation exchange administrative and professional support services in support of operations. These services are priced at either the fully loaded cost or at the higher of fully loaded cost or fair market value depending on the nature of the services provided. PG&E Corporation also allocates certain other corporate administrative and general costs to the Utility and other subsidiaries using a variety of factors, including their share of employees, operating expenses, assets, and other cost causal methods. Additionally, the Utility purchases gas commodity and transmission services from, and sells reservation and other ancillary services to, PG&E NEG. These services are priced at either tariff rates or fair market value depending on the nature of the services provided. Intercompany transactions are eliminated in consolidation and no profit results from these transactions.

In response to the September 11, 2001, terrorist attacks, PG&E Corporation and the Utility increased security measures at critical facilities. PG&E Corporation and the Utility continue to maintain a heightened state of alert at all facilities as well as close coordination with federal, state, and local law enforcement agencies.

PG&E Corporation and the Utility apply SFAS No. 71 to their regulated operations. This standard allows a cost to be capitalized, that otherwise would be charged to expense if it is probable that the cost is recoverable through regulated rates. This standard also allows a regulator to create a liability that is recognized in the financial statements. PG&E Corporation and the Utility's regulatory assets and liabilities are discussed further in Note 1 in the Notes to the Consolidated Financial Statements.

The Utility also used the guidance included in SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," when in 2000 it concluded that $6.9 billion of regulatory assets was not probable of recovery and wrote off its generation-related regulatory assets and under-collected purchased power costs. See Note 3 of the Notes to the Consolidated Financial Statements for further discussion. PG&E NEG also applied SFAS No. 121 when it wrote down its investment in PG&E GTT and the PG&E Energy Services business unit.

The Utility's 2001 financial statements are presented in accordance with SOP 90-7, which is used for entities in reorganization under the bankruptcy code.

Effective 2001, PG&E Corporation and the Utility adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS No. 138, "Accounting for Certain Derivative Instruments and Hedging Activities" (collectively, SFAS No. 133), which required all financial instruments to be recognized in the financial statements at market value. See further discussion in "Quantitative and Qualitative Disclosure about Market Risk" above, and Notes 4 and 5 of the Notes to the Consolidated Financial Statements. PG&E NEG accounts for its energy trading activities in accordance with EITF 98-10 and SFAS No. 133, which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting. EITF 98-10 also allows two methods of recognizing energy trading contracts in the income statement. The "gross" method provides that the contracts are recorded at their full value in revenues and expenses. The other method is the "net" method in which revenues and expenses are netted and only the trading margin (or when realized sometimes trading loss) is reflected in revenues. PG&E NEG used the gross method for those energy trading contracts for which they have a choice.

PG&E Corporation commodities and service revenues derived from power generation are recognized upon output, product delivery or satisfaction of specific targets. Regulated gas and electric revenues are recorded as services are provided based upon applicable tariffs and include amounts for services rendered but not yet billed.

Effective January 1, 2001, PG&E Corporation and the Utility adopted SFAS No. 133, as amended. SFAS No. 133 requires PG&E Corporation and the Utility to recognize all derivatives, as defined on the balance sheet at fair value. PG&E Corporation's transition adjustment to implement this new SFAS No. 133 on January 1, 2001, resulted in a non-material decrease to earnings and an after-tax decrease of $243 million to accumulated other comprehensive income. The Utility's transition adjustment to implement SFAS No. 133 resulted in a non-material decrease to earnings and an after-tax $90 million positive adjustment to accumulated other comprehensive loss. These transition adjustments, which relate to hedges of interest rate, foreign currency, and commodity price risk exposure, were recognized as of January 1, 2001, as a cumulative effect of a change in accounting principle.

Derivatives are classified as price risk management assets and price risk management liabilities on the balance sheet. Derivatives, or any portion thereof, that are not effective hedges are adjusted to fair value through income. For derivatives that are effective hedges, depending on the nature of the hedge, changes in the fair value are either offset by changes in the fair value of the hedged assets or liabilities through earnings or recognized in accumulated other comprehensive income (loss) until the hedged item is recognized in earnings. Net gains or losses on derivative instruments recognized for the year ended December 31, 2001, were included in various lines on the Consolidated Statements of Operations, including energy commodities and services revenue, cost of energy commodities and services, interest income or interest expense, and other income (expense), net.

PG&E Corporation also has derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. These derivatives 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. In June 2001 (as amended in October 2001 and December 2001), the Financial Accounting Standards Board (FASB) approved an interpretation issued by the Derivatives Implementation Group (DIG) that changed the definition of normal purchases and sales for certain power contracts. PG&E Corporation must implement this interpretation on April 1, 2002, and is currently assessing the impact of these new rules. PG&E Corporation anticipates that implementation of this interpretation will result in several contracts failing to continue qualifying for the normal purchases and sales exemption, possibly resulting in these contracts being marked-to-market through earnings. The FASB has also approved another DIG interpretation that disallows normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Certain of PG&E Corporation's derivative commodity contracts may no longer be exempt from the requirements of the Statement. PG&E Corporation is evaluating the impact of this implementation guidance on its financial statements, and will implement this guidance, as appropriate, by the implementation deadline of April 1, 2002.

To qualify for the normal purchases and sales exception from SFAS No. 133, a contract must have pricing that is deemed to be clearly and closely related to the asset to be delivered under the contract. In 2001, the FASB approved another interpretation issued by the DIG that clarifies how this requirement applies to certain commodity contracts. In applying this new DIG guidance, PG&E Corporation determined that one of its derivative commodity contracts no longer qualifies for normal purchases and sales treatment, and must be marked-to-market through

earnings. The cumulative effect of this change in accounting principle increased earnings by approximately $9 million (after-tax).

In June 2001, the FASB issued SFAS No. 141, "Business Combinations." This Statement, which applies to all business combinations accounted for under the purchase method completed after June 30, 2001, prohibits the use of pooling-of-interests method of accounting for business combinations and provides a new definition of intangible assets. This standard will be applied to any prospective acquisitions.

Also in June 2001, the FASB issued SFAS No. 142, "Goodwill and Other Intangible Assets." This Statement eliminates the amortization of goodwill, and requires that goodwill be reviewed at least annually for impairment. This Statement also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods be adjusted accordingly. This Statement is effective for fiscal years beginning after December 15, 2001, and affects all goodwill and other intangible assets recognized on a company's statement of financial position at that date, regardless of when the assets were initially recognized. This statement was adopted on January 1, 2002, and did not have a significant impact on the financial statements of PG&E Corporation and the Utility.

In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset Retirement Obligations." This Statement is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 provides accounting requirements for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under the Statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful life of the related asset. PG&E Corporation and the Utility are currently evaluating the impact of SFAS No. 143, but have not yet determined the effects of this Statement on their financial statements.

In October 2001, the FASB issued SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets," which addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 supersedes SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of," but retains the fundamental provisions for recognizing and measuring impairment of long-lived assets to be held and used or disposed of by sale. The Statement also supersedes the accounting and reporting provisions for the disposal of a segment of a business, and eliminates the exception to consolidation for a subsidiary for which control is likely to be temporary. SFAS No. 144 eliminates the conflict between accounting models for treating the disposition of long-lived assets that existed between SFAS No. 121 and the guidance for a segment of a business accounted for as a discontinued operation by adopting the methodology established in SFAS No. 121, and also resolves implementation issues related to SFAS No. 121. This Statement is effective for fiscal years beginning after December 15, 2001. PG&E Corporation and the Utility adopted this statement on January 1, 2002, and the adoption did not have any immediate impact on the financial statements of PG&E Corporation or the Utility.

In the normal course of business, both PG&E Corporation and the Utility are named as parties in a number of claims and lawsuits. See Note 16 of the Notes to the Consolidated Financial Statements for further discussion of significant pending legal matters.

PG&E Corporation

CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share amounts)