PG&E NATIONAL ENERGY GROUP INC - 10-Q Quarterly Report

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding twelve months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

As of March 31, 2003, there were 1,000 shares of common stock, $1 par value outstanding.

The accompanying Notes to the Consolidated Financial Statements are an integral part

PG&E National Energy Group, Inc. (PG&E NEG) was incorporated on December 18, 1998, as a subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E National Energy Group, LLC, a subsidiary of PG&E Corporation, owns most of the equity in PG&E NEG. During February and March of 2003, certain lenders of PG&E Corporation exercised options to purchase 3 percent of the shares of PG&E NEG. See Note 2 for additional discussion. PG&E NEG currently is focused on power generation and natural gas transmission in the United States. PG&E NEG’s principal subsidiaries 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); and

	•	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), which includes North Baja Pipeline, LLC.

PG&E NEG also has other less significant subsidiaries. Investments in affiliates in which PG&E NEG has the ability to exercise significant influence but not control are accounted for using the equity method.

PG&E NEG believes that the accompanying unaudited Consolidated Financial Statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q. Certain amounts in the prior year’s unaudited and audited Consolidated Financial Statements have been reclassified to conform to the 2003 presentation. All significant intercompany transactions have been eliminated from the unaudited consolidated financial statements. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

This quarterly report should be read in conjunction with PG&E NEG’s Consolidated Financial Statements and Notes to Consolidated Financial Statements included in its 2002 Annual Report on Form 10-K, as amended, and its other reports filed with the Securities and Exchange Commission (SEC) since the 2002 Annual Report on Form 10-K, as amended, was filed.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets and liabilities, and disclosures of contingencies. As these estimates involve judgments on a wide range of factors, including future economic conditions that are difficult to predict, actual results could differ from these estimates.

PG&E NEG’s Consolidated Financial Statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets, and repayment of liabilities in the ordinary course of business. However, as a result of current liquidity concerns and restructuring discussions with PG&E NEG, its subsidiaries, and their lenders and the likelihood of a bankruptcy filing, such realization of assets and liquidation of liabilities are subject to uncertainty.

been engaged in discussions to restructure PG&E NEG’s and its subsidiaries’ debt obligations and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy Code. Although PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of PG&E NEG and its subsidiaries. Absent a negotiated agreement, the lenders may exercise their default remedies or force PG&E NEG and certain of its subsidiaries into an involuntary proceeding under the Bankruptcy Code. Notwithstanding the status of current negotiations, PG&E NEG and certain of its subsidiaries also may elect to voluntarily seek protection under the Bankruptcy Code as early as the second quarter 2003.

The Consolidated Financial Statements of PG&E NEG include the accounts of PG&E NEG and its wholly owned and controlled subsidiaries. PG&E NEG has investments in various power generation and other energy projects which PG&E NEG does not control. The equity method of accounting is applied to these investments in affiliated entities, which include corporations, limited liability companies, and partnerships. Under this method, PG&E NEG’s share of equity income or losses of these entities is reflected as equity in earnings of affiliates.

The Consolidated Statements of Operations include all revenues and costs directly attributable to PG&E NEG, including costs for functions and services performed by centralized PG&E Corporation organizations and directly charged to PG&E NEG based on usage or other allocation factors. The Results of Operations in these Consolidated Financial Statements also include general corporate expenses allocated by PG&E Corporation to PG&E NEG based on assumptions that management believes are reasonable under the circumstances. However, these allocations may not necessarily be indicative of the costs and expenses that would have resulted if PG&E NEG had operated as a separate entity.

Except as disclosed below, PG&E NEG is following the same accounting principles discussed in its 2002 Annual Report on Form 10-K, as amended.

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

FIN 45 elaborates on existing disclosure requirements for most guarantees. It also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that specified triggering events or conditions occur. This information also must be disclosed in interim and annual financial statements.

FIN 45 does not prescribe a specific account for the guarantor’s offsetting entry when it recognizes the liability at the inception of the guarantee, noting that the offsetting entry would depend on the circumstances in which the guarantee was issued. There also is no prescribed approach included for subsequently measuring the guarantor’s recognized liability over the term of the related guarantee. It is noted that the liability typically would be reduced by a credit to earnings as the guarantor is released from risk under the guarantee. The adoption of this interpretation did not have a material impact on the Consolidated Financial Statements of PG&E NEG.

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

PG&E NEG has identified its generating facilities as having asset retirement obligations as of January 1, 2003. Upon implementation of this Statement, PG&E NEG recorded $2 million to its property, plant and equipment to reflect the fair value of the asset retirement costs as of the date the obligation was incurred, and recognized $3 million for asset retirement obligations. The cumulative effect of the change in accounting principle as a result of adopting this Statement was a loss of $5 million, net of zero tax benefits. The impact to PG&E NEG of implementing SFAS No. 143 by its unconsolidated affiliates is immaterial.

If this Statement had been adopted on January 1, 2002, the pro forma effects on earnings of the accounting change for the three months ended March 31, 2002, would not have been material.

PG&E GTN may have potential asset retirement obligations under various land right documents associated with its gas transmission facilities. The majority of PG&E GTN’s land rights are perpetual. Any non-perpetual land rights generally are renewed continuously because PG&E GTN intends to utilize these facilities indefinitely. Since the timing and extent of any potential asset retirements is unknown, the fair value of any obligations associated with these facilities cannot be reasonably estimated.

PG&E GTN collects estimated removal costs in rates through depreciation in accordance with regulatory treatment. These amounts do not represent SFAS No. 143 asset retirement obligations and will continue to be recorded within accumulated depreciation. PG&E GTN estimated the related removal costs accrued within accumulated depreciation were approximately $11.5 million at March 31, 2003.

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

Change from Gross to Net Method of Reporting Revenues and Expenses on Trading Activities — Effective the third quarter ended September 30, 2002, PG&E NEG changed its method of reporting gains and losses associated with energy trading contracts from the gross method of presentation to the net method. PG&E NEG believes that the net method provides a more accurate and consistent presentation of energy trading activities on the financial statements. Amounts to be presented under the net method include all gross margin elements related to energy trading activities.

Before implementation of the net method and the subsequent rescission of EITF Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities,” (EITF 98-10), as noted below, PG&E NEG had reported unrealized gains and losses on trading activities on a net basis in operating revenues. However, PG&E NEG had reported realized gains and losses on a gross basis in operating

income, as both operating revenues and costs of commodity sales and fuel. PG&E NEG now is reporting realized gains and losses from trading activities on a net basis as operating revenues, and in accordance with the rescission of EITF 98-10, unrealized gains and losses on energy trading activities no longer are reported as these contracts are accounted for under the cost method.

Implementation of the net method has no net effect on gross margin, operating income, or net income. Accordingly, PG&E NEG continues to report realized income from non-trading activities on a gross basis in operating revenues and operating expenses. Prior year financial statements have been reclassified to conform to the net method.

The schedule below summarizes the amounts impacted by the change in methodology on PG&E NEG’s Consolidated Statements of Operations for the three months ended March 31, 2002 (in millions):

Rescission of EITF 98-10 — In October 2002, the EITF rescinded EITF 98-10. Energy trading contracts that are derivatives in accordance with SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (collectively, SFAS No. 133), will continue to be accounted for at fair value under SFAS No. 133. Contracts that were previously marked to market as trading activities under EITF 98-10 that did not meet the definition of a derivative are now accounted for at cost, through a one-time adjustment recorded as a cumulative effect of a change in accounting principle. This requirement was effective as of January 1, 2003, resulting in PG&E NEG recording a $3 million loss, net of zero tax benefits as a cumulative effect of accounting change. For PG&E NEG, the majority of trading contracts are derivative instruments as defined in SFAS No. 133. The rescission of EITF 98-10 has no effect on the accounting for derivative instruments used for non-trading purposes, which continue to be accounted for in accordance with SFAS No. 133. The reporting requirements associated with the rescission of EITF 98-10 were applied prospectively for all EITF 98-10 energy trading contracts entered into after October 25, 2002, although the number of energy trading contracts subject to the prospective implementation was considered immaterial.

PG&E NEG accounts for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” as allowed by the SFAS No. 123, “Accounting for Stock-Based Compensation,” as amended by SFAS No. 148, “Accounting for Stock-Based Compensation Transition and Disclosure, an Amendment of FASB Statement No. 123.” Under the intrinsic value method, PG&E NEG does not recognize any compensation expense for stock options, as the exercise price is equal to the fair market value of a share of PG&E Corporation’s common stock at the time the options are granted. Had compensation expense been recognized

using the fair value-based method under SFAS No. 123, PG&E NEG’s pro-forma consolidated earnings (loss) would have been as follows (in millions):

On January 2, 2003, PG&E Corporation awarded 101 thousand shares of restricted PG&E Corporation common stock to eligible employees of PG&E NEG and its subsidiaries. The shares were granted with restrictions and are subject to forfeiture unless certain conditions are met.

The restricted shares were issued at the grant date and are held in an escrow account. The shares become available to the employees as the restrictions lapse. In general, the restrictions on 80 percent of the shares lapse automatically over a period of four years at the rate of 20 percent per year. Restrictions to the remaining 20 percent of the shares will lapse at a rate of 5 percent per year if PG&E Corporation is in the top quartile of its comparator group as measured by annual total shareholder return for each year ending immediately before each annual lapse date.

Total compensation expense resulting from the restricted stock issuance reflected on PG&E NEG’s Consolidated Statements of Operations for the three months ended March 31, 2003, was immaterial.

PG&E NEG’s comprehensive income (loss) consists principally of changes in the market value of certain cash flow hedges under SFAS No. 133, as amended (in millions).

OCI is stated net of taxes of zero at March 31, 2003, and $38 million at March 31, 2002.

Amendment of Statement 133 on Derivative Instruments and Hedging Activities — In April 2003, the Financial Accounting Standards Board (FASB) issued Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS No. 149). SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. The amendments in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly. The Statement clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash

flows. In addition, the Statement amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”, and amends certain other existing pronouncements. The provisions of the Statement that relate to SFAS No. 133 Implementation Issues that have been effective for periods that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.

The requirements of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. PG&E NEG is currently evaluating the impacts, if any, of SFAS No. 149 on its Consolidated Financial Statements.

Consolidation of Variable Interest Entities — In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46), which expands upon existing accounting guidance addressing when a company should include in its financial statements the assets, liabilities, and activities of another entity or arrangement it is involved with. FIN 46 notes that many of what are now referred to as “variable interest entities” have commonly been referred to as special-purpose entities or off-balance sheet structures. However, the Interpretation’s guidance is to be applied to not only these entities but to all entities and arrangements found within a company. FIN 46 provides some general guidance as to the definition of a variable interest entity. PG&E NEG is currently evaluating all entities and arrangements it is involved with to determine if they meet the FIN 46 criteria as variable interest entities.

Until the issuance of FIN 46, one company generally included another entity in its consolidated financial statements only if it controlled the entity through voting interests. FIN 46 changes that by requiring a variable interest entity to be consolidated by a company if that company is subject to a majority of the risk of loss from the variable interest entity’s activities or entitled to receive a majority of the entity’s residual returns, or both. A company that consolidates a variable interest entity is now referred to as the “primary beneficiary” of that entity.

FIN 46 requires disclosures of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.

The consolidation requirements of FIN 46 apply immediately to variable interest entities created after January 31, 2003. There were no new variable interest entities created by PG&E NEG between February 1, 2003 and March 31, 2003. The consolidation requirements apply to variable interest entities created before January 31, 2003 in the first fiscal year or interim period beginning after June 15, 2003, so these requirements would be applicable to PG&E NEG in the third quarter 2003. Certain new and expanded disclosure requirements must be applied to PG&E NEG’s March 31, 2003 disclosures if there is an assessment that it is reasonably possible that an enterprise will consolidate or disclose information about a variable interest equity when FIN 46 becomes effective. PG&E NEG is currently evaluating the impacts of Interpretation No. 46’s initial recognition, measurement, and disclosure provisions on its Consolidated Financial Statements.

In 2002, PG&E NEG recorded valuation allowances due to continued uncertainty in realizing both federal and state deferred tax assets. These valuation allowances were determined on a stand-alone basis. During the first quarter of 2003, valuation allowances of $76 million were recorded in continuing operations. Additional valuation allowances of $45 million were recorded in discontinued operations, $3 million recorded in cumulative effect of a change in an accounting principle, and $53 million recorded in accumulated other comprehensive loss. These valuation allowances were established for the full amount of the federal and state deferred taxes.

PG&E Corporation and PG&E NEG have previously disclosed that certain lenders of PG&E Corporation had received an option to purchase up to 3 percent of the shares of PG&E NEG in connection with PG&E Corporation’s credit agreement dated March 1, 2001, and that on February 25, 2003, General Electric Capital Corporation, or GECC, exercised the options it held, representing 1.8 percent of the common stock of PG&E NEG. In PG&E NEG’s and PG&E Corporation’s Annual Reports on Form 10-K (including the portions of PG&E Corporation Annual Report to Shareholders that were incorporated by reference into PG&E Corporation’s Annual Report on Form 10-K), PG&E NEG and PG&E Corporation disclosed that the remaining options held by the other lenders under the March 1, 2001 credit agreement, representing 1.2 percent of the common stock of PG&E NEG, were required to be exercised by March 1, 2003 and that such options had therefore expired. After reconsideration of the operative documents, it was determined that the additional options did not expire and a Current Report on Form 8-K was filed. On March 27 and March 28, 2003, the other lenders timely exercised their options. Thus, 3 percent of the equity of PG&E NEG is now owned by GECC, Lehman Brothers, Inc. and the other lenders under the March 1, 2001 PG&E Corporation credit agreement.

As of December 31, 2001, PG&E NEG had replaced or eliminated all of the previously issued PG&E Corporation guarantees and two guarantees of non-debt obligations of other PG&E NEG subsidiaries (except for a $16 million office lease guarantee relating to PG&E NEG’s San Francisco office, two guarantees of PG&E NEG’s indemnification obligations to purchasers of PG&E NEG’s assets and a guarantee related to PG&E NEG’s obligations to the sellers of assets purchased by PG&E NEG) with a combination of guarantees provided by PG&E NEG or its subsidiaries and letters of credit obtained independently by PG&E NEG. The $16 million office lease guarantee was reduced to $9.7 million as of December 31, 2002 and no further change was made through the first quarter of 2003.

As of December 31, 2002 and March 31, 2003, Attala Power Corporation (APC), an indirect, subsidiary of PG&E NEG, had a non-recourse demand note payable to PG&E Corporation of $209 million. The APC note is classified as long-term on the Consolidated Balance Sheets as of March 31, 2003. The demand note between APC and PG&E Corporation is recourse only to APC and not to PG&E NEG. Interest is accrued on the note quarterly based on the London interbank offer rate plus a 2.5 percent margin. At March 31, 2003, accrued interest of $4.3 million was recorded.

In addition, as of March 31, 2003, other subsidiaries of PG&E NEG had net amounts payable in the amount of $118 million in the form of promissory notes to PG&E Corporation, related primarily to past funding of generating asset development and acquisition, and these amounts payable are classified as long-term on the Consolidated Balance Sheet.

In accordance with various arrangements, PG&E NEG and its subsidiaries enter into transactions with Pacific Gas and Electric Company (Utility), another subsidiary of PG&E Corporation and PG&E Corporation to provide and receive various services. The principal nature of the transactions between the Utility and PG&E NEG is the purchase and sale of energy commodities through PG&E ET and transportation services with PG&E GTN. These services are priced at either tariff rates or fair market value depending on the nature of the services provided.

The following table summarizes the significant related party transactions for PG&E NEG and its subsidiaries (in millions).


^(A)	This amount includes $22 million of pre-bankruptcy claims. The Utility is current on amounts owed to PG&E ET arising after the Utility’s April 6, 2001, bankruptcy filing. On January 31, 2003, PG&E ET sold its $22 million pre-bankruptcy claim for approximately $18 million.

^(B)	This amount includes $3 million in bankruptcy claims. Subsequent to the Bankruptcy the Utility is current on all subsequent obligations. In accordance with PG&E GTN’s Federal Energy Regulatory Commission (FERC) tariff provisions, the Utility has provided assurances in the form of cash to support its position as a shipper on the PG&E GTN pipeline.

^(C)	Includes margin deposits of $8 million.

PG&E Corporation exchanges administrative and professional support services in support of operations. These services are priced either at the fully based cost (i.e. direct costs and allocation of overhead costs) or the higher of fully based cost or fair market value, depending on the nature of the services provided. Additionally, PG&E Corporation allocates certain other corporate administrative and general costs to PG&E NEG and its subsidiaries. A variety of factors are used when allocating these costs, which are based upon the number of employees, operating expenses, total assets, and other cost causal methods. Allocated costs totaled $1.9 million for three months ended March 31, 2003 and $6.3 million for the three months ended March 31, 2002. The total accumulated amount due to PG&E Corporation for administrative and professional support services and other assigned costs totaled $18.2 million at March 31, 2003.

Prior to July 31, 2002, most of the various debt instruments of PG&E NEG and its subsidiaries carried investment-grade credit ratings as assigned by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), two major credit rating agencies. Since July 31, 2002, PG&E NEG’s rated entities have been downgraded several times. The result of these downgrades has left all of PG&E NEG consolidated rated entities and debt instruments at below investment-grade.

The downgrade of PG&E NEG’s credit ratings impacted various guarantees and financial arrangements that require PG&E NEG to maintain certain credit ratings from S&P and/or Moody’s. Because of the downgrades, PG&E NEG’s counterparties have demanded that PG&E NEG provide additional security for performance in the form of cash, letters of credit, acceptable replacement guarantees, or advanced funding of obligations. Other counterparties continue to have the right to make such demands. If PG&E NEG fails to provide this additional collateral within defined cure periods, PG&E NEG may be in default under contractual terms. In addition to agreements containing ratings triggers, other agreements allow counterparties to seek

additional security for performance whenever such counterparty becomes concerned about PG&E NEG’s or its subsidiaries’ creditworthiness. PG&E NEG’s credit downgrades constrained its access to additional capital and triggered increases in cost of indebtedness under many of its outstanding debt arrangements.

The credit downgrades also impacted PG&E NEG’s and its subsidiaries’ ability to service their financial obligations by putting constraints on the ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E NEG’s subsidiaries now must independently determine, in light of each company’s financial situation, whether any proposed dividend, distribution, or intercompany loan is permitted and is in such subsidiary’s interest.

The effects of the credit downgrades on PG&E NEG’s debt facilities and other contractual arrangements are described below. Amounts required to be paid under debt agreements and other significant contractual commitments also are described below.

PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.7 billion, but this debt is non-recourse to PG&E NEG. On November 14, 2002, PG&E NEG defaulted on the repayment of the $431 million 364-day tranche of its corporate revolving credit facility (Corporate Revolver). Loans and letters of credit outstanding as of March 31, 2003 under the two-year tranche of the Corporate Revolver were $258 million, consisting of $185 million of letters of credit and $73 million of loans. The default under the Corporate Revolver also constitutes a cross-default as of March 31, 2003, under (1) PG&E NEG’s Senior Unsecured Notes ($1 billion outstanding), (2) its guarantee of a turbine revolving credit agreement ($205 million outstanding), and (3) various equity commitment guarantees totaling $960 million. In addition, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under the PG&E NEG Senior Unsecured Notes. PG&E NEG currently does not have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.

PG&E NEG, its subsidiaries, and their lenders have been engaged in discussions to restructure PG&E NEG’s and its subsidiaries’ debt obligations and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy Code. Although PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of PG&E NEG and its subsidiaries. Absent a negotiated agreement, the lenders may exercise their default remedies or force PG&E NEG and certain of its subsidiaries into an involuntary proceeding under the Bankruptcy Code. Notwithstanding the status of current negotiations, PG&E NEG and certain of its subsidiaries also may elect to voluntarily seek protection under the Bankruptcy Code as early as the second quarter 2003.

The schedule below summarizes PG&E NEG’s and its subsidiaries outstanding debt in default and long-term debt as of March 31, 2003 and December 31, 2002 (in millions):

Accrued Interest — For the period ended March 31, 2003, accrued interest was recorded on the following debt instruments (in millions):

GenHoldings Construction Facility — In December 2001, PG&E NEG entered into a $1.075 billion 5-year non-recourse credit facility for a portfolio of generating projects, held by GenHoldings I, LLC (GenHoldings), an indirect subsidiary of PG&E NEG. The credit facility which increased to $1.460 billion on April 5, 2002, is secured by the Millennium, Harquahala, Covert, and Athens projects. The facility was intended to be used to reimburse PG&E NEG and lenders for a portion of the construction costs already incurred on these projects and to fund a portion of the balance of the construction costs through completion.

GenHoldings has defaulted under its credit agreement by failing to make equity contributions to fund construction draws for the Athens, Harquahala, and Covert projects. In November and December 2002, GenHoldings’ lenders executed waivers and amendments to the credit agreement under which they agreed to continue to waive GenHoldings’ equity default until March 31, 2003 and increased loan commitments to cover such shortfall.

In connection with the lenders’ waiver of various defaults and additional funding commitments, PG&E NEG has agreed to cooperate with any reasonable proposal by the lenders regarding disposition of the equity in or assets of any or all of the PG&E NEG subsidiaries holding the Athens, Covert, Harquahala and Millennium projects.

As of March 21, 2003, the lenders executed a waiver letter extending to June 30, 2003, the waiver of GenHoldings’ equity default. In addition, the waiver letter also waives other existing defaults in order to permit the continued availability of loan facilities to fund construction and operation of the projects until such time as a transfer of the projects to the GenHoldings lenders may be completed. An event of default will occur if such transfer is not accomplished by such deadline. Such a default would trigger lender remedies, including the right to foreclose on the Millennium, Harquahala, Athens, and Covert projects.

Under the waiver, PG&E NEG has re-affirmed its guarantee of GenHoldings’ remaining obligation to make equity contributions to these projects of approximately $355 million. Neither PG&E NEG nor GenHoldings currently expects to have sufficient funds to make this payment. The requirement to pay $355 million will remain an obligation of PG&E NEG that would survive the transfer of the projects.

Lake Road and La Paloma Construction Facilities — In September 1999 and March 2000, Lake Road Generating Company, LP (Lake Road) and La Paloma Generating Company, LLC (La Paloma) entered into Participation Agreements to finance the construction of the two plants. In November 2002, Lake Road and La Paloma defaulted on their obligations to pay interest and swap payments. In addition, as a result of PG&E NEG’s downgrade to below investment grade by both S&P and Moody’s, PG&E NEG, as guarantor of certain debt obligations of Lake Road and La Paloma, became required to make equity contributions to Lake Road and La Paloma of $230 million and $375 million respectively. The lenders have accelerated all debt existing prior to December 11, 2002, including the guaranteed portion of the debt and made a payment under the PG&E NEG guarantee. Neither PG&E NEG, Lake Road nor La Paloma has sufficient funds to make these payments.

As of December 4, 2002, PG&E NEG and certain subsidiaries entered into various agreements with the respective lenders for each of the Lake Road and La Paloma generating projects providing for (1) funding of construction costs required to complete the La Paloma facility, and (2) additional working capital facilities to enable each subsidiary to timely pay for its fuel requirements and to provide its own collateral to support natural gas pipeline capacity reservations and independent transmission system operator requirements, as well as for general working capital purposes. Lenders extending new credit under these agreements have received liens on the projects that are senior to the existing lenders’ liens. These agreements provide, among other things, that the failure to transfer right, title and interest in, to and under the Lake Road and La Paloma projects to the respective lenders by June 9, 2003 will constitute a default under the agreements. The failure to transfer the facilities would entitle the lenders to accelerate the new indebtedness and exercise other remedies. The requirement to pay $230 million and $375 million for Lake Road and La Paloma, respectively, will remain an obligation of PG&E NEG that would survive the transfer of the projects.

PG&E NEG has substantial financial commitments and contingencies in connection with agreements entered into supporting PG&E NEG’s operating, construction, and development activities. These commitments and contingencies are discussed more fully in the PG&E NEG’s 2002 Annual Report on Form 10-K, as amended. The following summarizes cancelled, new, and significantly modified commitments since the 2002 Annual Report on Form 10-K, as amended, was filed and all material contingencies.

In addition to the outstanding balances under the credit facilities described in Note 3, PG&E NEG has commitments available under facilities to issue letters of credit. The following table lists the various letter of credit facilities that have the capacity to issue letters of credit (in millions):

PG&E ET entered into tolling agreements with several counterparties under which it, at its discretion, supplies the fuel to the power plants and then sells the plant’s output in the competitive market. Payments to

counterparties are reduced if the plants do not achieve agreed-upon levels of performance. The face amount of PG&E NEG’s and its subsidiaries’ guarantees relating to PG&E ET’s tolling agreements is approximately $600 million. The tolling agreements are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million; and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty — Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PG&E ET to replace the guarantee and post security in the amount of $150 million. PG&E ET has not posted such security. Under the terms of the guarantees to Liberty, Liberty has the right to terminate the agreement and seek recovery of a termination payment for a maximum amount of up to $150 million. Liberty first must proceed against PG&E NEG’s guarantee, and can demand payment under PG&E GTN’s guarantee only if (1) PG&E NEG is in bankruptcy, or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

DTE-Georgetown — By letter dated October 14, 2002, DTE provided notice to PG&E ET that the downgrade of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE and that PG&E ET was required to post replacement security within ten days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.

Calpine — The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement and construction contractor for the Otay Mesa facility. On October 16, 2002 PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002 that it was terminating the tolling agreement effective November 29, 2002. Calpine has indicated that this termination was improper and constituted a default under the agreement, but has not taken any further action.

Southaven and Caledonia Tolling Agreements — PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the tolling agreement. The amount of the guarantee does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement, and because PG&E ET had failed to provide, within 30 days from the downgrade, substitute credit support that meets the requirement of the tolling agreement. Under the tolling agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET provided Southaven with a notice of default respecting Southaven’s performance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

In addition, PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, pursuant to which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the agreement. The amount of the guarantee does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement, and because PG&E ET had failed to provide, within 30 days from the downgrade substitute credit support that met the requirements of the tolling agreement. Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET provided Caledonia with a notice of default respecting Caledonia’s performance under the tolling agreement concerning the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

On February 7, 2003, Southaven and Caledonia filed emergency petitions to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court of Montgomery County, Maryland. On March 3, 2003, the court issued an order ruling that PG&E ET must continue to perform under the agreements. PG&E ET appealed this decision to an intermediate Maryland appellate court. However, on April 8, the highest appellate court in Maryland issued on its own motion an order taking jurisdiction of the appeal.

PG&E ET is not able to predict whether the counterparties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether or the extent to which, these proceedings will have a material adverse effect on PG&E NEG’s financial condition or results of operations.

Under each tolling agreement, determination of the termination payment is based on a formula that takes into account a number of factors including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG currently does not expect to be able to pay any termination payments that may become due.

PG&E NEG and certain subsidiaries have provided guarantees as of March 31, 2003 to approximately 188 counterparties in support of PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio in the face amount of $2.2 billion. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully used at any time. As of March 31, 2003, PG&E NEG and its rated subsidiaries’ aggregate exposure under these guarantees was approximately $150 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.

At March 31, 2003, PG&E ET’s estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $96 million.

To date, PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements, although one counterparty has alleged a default. No demands have been made upon the guarantors of PG&E ET’s obligations under these trading agreements. In the past, PG&E ET has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET’s liquidity. PG&E NEG’s and its subsidiaries’ ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG’s financial condition and the degree of liquidity in the energy markets. The actual calls for collateral will depend largely upon the ability to enter into forbearance agreements and pre- and early-pay arrangements with counterparties, the continued performance of PG&E NEG companies under the underlying agreements with counterparties, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties’ other commercial considerations.

PG&E NEG has provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees relate to performance under certain construction contracts. In the event PG&E NEG is unable to provide any additional or replacement security that may be required as a result of rating downgrades, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages. These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG’s power plants and pipelines. These guarantees are described below.

PG&E NEG has issued guarantees to construction financing lenders for the performance of the contractors building the Harquahala and Covert generating projects for up to $555 million. See additional discussion in the “Legal Matters” section below.

PG&E NEG has issued $100 million of guarantees to the construction contractor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements. See additional discussion in the “Legal Matters” section below.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly-owned subsidiary, Attala Energy Company, LLC, has entered into with another wholly-owned subsidiary, Attala Generating Company, LLC.

The balance of the guarantees are for commitments undertaken by PG&E NEG or subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.

In May 2000, USGen New England, Inc. (USGenNE), an indirect subsidiary of 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 USGenNE to provide certain information relative to the compliance of its Brayton Point and Salem Harbor plants with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had preliminary discussions with the EPA to explore a potential settlement of this matter. Management 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.

As a result of the EPA Information Request and environmental regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to achieve significant reductions of sulfur dioxide and nitrogen oxide emissions. Additional requirements for the control of mercury and carbon dioxide emissions also will be forthcoming as part of these regulatory initiatives. Management believes that USGenNE 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 could approximate $376 million over the next four years. These estimates are currently under review and it is possible that actual expenditures may be higher. Based on an emission control plan filed for Brayton Point under the regulations implementing these initiatives, the Massachusetts Department of Environmental Protection (DEP) ruled that Brayton Point is required to meet the newer, more stringent emission limitations for sulfur dioxide and nitrogen oxide by 2006. However, on June 7, 2002, the DEP ruled that Salem Harbor must satisfy these limitations by 2004. In April 2002, USGenNE filed with DEP a revised plan for Salem Harbor that it believes meets the DEP requirements for the 2006 compliance date. USGenNE has since filed a number of appeals challenging this decision and unless and until the decision is reversed, the compliance date for Salem Harbor remains October 2004. USGenNE will not be able to operate Salem Harbor unless it is in compliance with these emission limitations. PG&E NEG believes that it is impossible to meet the October 2004 deadline. Therefore, it may not be able to operate the facility after that deadline. USGenNE and the DEP recently have agreed to enter into negotiations concerning a Salem Harbor compliance schedule with the DEP regulation on a schedule that USGenNE could meet, assuming that financing and all other necessary approvals are in place.

Various aspects of the DEP’s regulations allow for public participation in the process through which DEP determines whether the 2004 or 2006 deadline applies and approves the specific activities that USGenNE will undertake to meet the new regulations. A number of local environmental groups are now participants in this process.

The EPA is required under the CAA to establish new regulations for controlling hazardous air pollutants from combustion turbines and reciprocating internal combustion engines. Although the EPA has yet to propose the regulations, the CAA required that they be promulgated by November 2000. Another provision in the CAA requires companies to submit case-by-case Maximum Achievable Control Technology (MACT) determinations for individual plants if the EPA fails to finalize regulations within eighteen months past the deadline. The EPA has extended this deadline through previous rulemakings. In late 2002, EPA proposed a rule that would require the case-by-case MACT applications to be submitted by October 30, 2003 if the EPA has not promulgated a MACT rule as of that date. The EPA intends to finalize the MACT regulations before this date, thus eliminating the need for the plant-specific permits. PG&E NEG will not be able to accurately quantify the economic impact of the future regulations until more details are available through the rulemaking process.

PG&E NEG’s existing power plants 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 (Salem Harbor, Manchester Street, and Brayton Point) are operating pursuant to National Pollutant Discharge Elimination System (NPDES) permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and all three facilities are continuing to operate under existing terms and conditions until new permits are issued. On July 22, 2002, the EPA and DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay.

Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE’s cost to comply with the new permit conditions could be as much as $248 million through 2006, but this is a preliminary estimate. There are various administrative and judicial

proceedings that must be completed before the draft NPDES permit for Brayton Point becomes final, and these proceedings are not expected to be completed during 2003. In addition, the EPA, as well as local environmental groups, previously expressed concern that the metal vanadium is not addressed at Brayton Point or Salem Harbor under the terms of the old NPDES permits. Based upon the lack of an identified control technology, USGenNE believes it is unlikely that the EPA will require that vanadium be addressed pursuant to a NPDES permit. However, if the EPA does insist on including vanadium in the NPDES permit, USGenNE may have to spend a significant amount to comply with such a provision. In addition, it is possible that the new permits for Salem Harbor and Manchester Street also may contain more stringent limitations than prior permits and that the cost to comply with the new permit conditions could be greater than the current estimate of $4 million. Lastly, the issuance of any final NPDES permits may be affected by the EPA’s proposed regulations under Section 316(b) of the Clean Water Act.

On March 27, 2002, the Rhode Island Attorney General notified USGenNE of his belief that Brayton Point “is in violation of applicable statutory and regulatory provisions governing its operations...” including “protections accorded by common law” respecting discharges from the facility into Mount Hope Bay. He stated that he intends to seek judicial relief “to abate these environmental law violations and to recover damages...” within the next 30 days. PG&E NEG believes that Brayton Point is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until the EPA issues a draft Clean Water Act NPDES permit for Brayton Point. The EPA issued this draft permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing this matter until he reviews USGenNE’s response to the draft permit which was submitted on October 4, 2002. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG’s financial condition or results of operation.

On April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using over 50 million gallons per day typically including some form of “once-through” cooling. Brayton Point, Salem Harbor, and Manchester Street are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed rule calls for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations are scheduled to be promulgated in February 2004. The extent to which they may require additional capital investment will depend on the timing of the NPDES permit proceedings for the affected facilities.

During April 2000, an environmental group served USGenNE and other PG&E NEG’s subsidiaries with a notice of its intent to file a citizen’s suit under the Resource Conservation Recovery Act. In September 2000, PG&E NEG signed a series of agreements with the DEP and the environmental group to resolve these matters that require PG&E NEG to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the activities during 2000 and is expected to complete them in 2003. PG&E NEG incurred expenditures related to these agreements of $5.4 million in 2000, $2.6 million in 2001 and $4.7 million in 2002. In addition to the costs previously incurred, PG&E NEG maintains a reserve in the amount of $6 million relating to its estimate of the remaining expenditures to fulfill its obligations under these agreements. PG&E NEG has deferred costs associated with capital expenditures and has set up a receivable account for amounts it believes are probable of recovery from insurance proceeds.

PG&E NEG believes that it may be required to spend up to approximately $636 million, excluding insurance proceeds, through 2008 for environmental compliance to continue operating these facilities. 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. PG&E NEG has not made any commitments to spend these amounts. In the event PG&E NEG does not spend or is unable to spend because of liquidity constraints amounts needed in order to

comply with these requirements, PG&E NEG may not be able to continue to operate one or all of these facilities.

Global climate change is a significant environmental issue that is likely to require sustained global action and investment over many decades. PG&E NEG has been engaged on the climate change issue for several years and is working with others on developing appropriate public policy responses to this challenge. PG&E NEG continuously assesses the financial and operational implications of this issue; however, the outcome and timing of these initiatives are uncertain.

PG&E NEG emits varying quantities of six greenhouse gases, including carbon dioxide and methane, in the course of its operations. Depending on the ultimate regulatory regime put into place for greenhouse gases, PG&E NEG’s operations, cash flows and financial condition could be adversely affected. Given the uncertainty of the regulatory regime, it is not possible to predict the extent to which climate change regulation will have a material adverse effect on PG&E NEG’s financial condition or results of operations.

In the normal course of business, PG&E NEG is named as a party in a number of claims and lawsuits. The most significant of these are discussed below.

NSTAR Electric & Gas Corporation — On May 14, 2001, NSTAR Electric & Gas Corporation (NSTAR) the Boston-area retail electric distribution utility holding company, filed a complaint at the FERC contesting the market-based rate authority of PG&E ET-Power and affiliates of Sithe Energies, Inc. (Sithe). In support of its complaint, NSTAR argues that the Northeastern Massachusetts Area (NEMA), at times suffers transmission constraints that limit the delivery of power into NEMA and that PG&E ET-Power and Sithe possess market power based on their share of generation within NEMA. NSTAR requests remedies including revocation of the suppliers’ market-based pricing authority during periods of transmission congestion into NEMA, divestiture of generation resources in NEMA, imposition of a rate cap on the suppliers’ generation resources during transmission constraints based on the marginal cost of production of those resources, and more effective and open exercise of market monitoring and mitigation by Independent System Operator-New England (ISO-New England), the independent system operator for the New England control area (NEPOOL). Under the NEPOOL market rules and procedures, ISO-New England is empowered to monitor and mitigate bids during periods of transmission congestion. PG&E NEG believes that ISO-New England has actively mitigated bids and has used its authority to mitigate the impact of transmission constraints on costs within NEMA and that PG&E ET-Power has operated its resources in compliance with NEPOOL market rules and procedures and applicable law. In addition, PG&E ET-Power and its affiliate, USGenNE, the entity that owns the generating assets located in NEPOOL, have had their market-based rate authority confirmed by the FERC on two prior occasions.

On February 5, 2002, NSTAR filed a petition for review with the United States Court of Appeals for the D.C. Circuit of the series of FERC Orders relating to ISO-New England’s implementation of its market mitigation authority under the NEPOOL Market Rules and Procedures 17 (MRP 17), which remains pending before the Court. On February 25, 2002, ISO-New England filed all agreements entered into pursuant to MRP 17, including its agreement with PG&E ET-Power with respect to Salem Harbor. The FERC has ruled that no refunds will be required with respect to the agreements for periods prior to acceptance by the FERC of the filing. NSTAR claims that until accepted by the FERC, these agreements cannot be effective and that any amounts collected pursuant to these agreements prior to their effectiveness must be refunded to the extent that amounts are in excess of certain rate formulas contained in MRP 17. PG&E ET-Power, as the party that bids USGenNE’s assets into the NEPOOL markets, entered into an agreement with ISO-New England for calendar years 2000, 2001, and 2002. This agreement sets forth terms on which bids from Salem Harbor Station Unit 4 may be mitigated without challenge by PG&E ET-Power. To date, bid amounts collected subject to the mitigation agreements are approximately $34.1 million.

In addition, on October 17, 2002, the FERC issued an order denying NSTAR’s complaint against PG&E ET-Power and Sithe, holding that MRP 17 was properly applied; that the prices ET-Power and Sithe charged were within the zone of reasonableness; and rejecting numerous other of NSTAR’s claims. PG&E NEG believes that the ultimate outcome of this litigation will not have a material adverse effect on its financial condition or results of operations.

FERC California Refund Proceeding — In a June 19, 2001 order, the FERC required that all public utility sellers and buyers in certain California markets participate in settlement discussions to complete the task of settling past accounts and structuring the new arrangements for California’s future energy markets. PG&E ET-Power is one such seller and buyer. These settlement discussions have been completed and they were not successful. As a result, the administrative law judge presiding over the discussions recommended to the FERC a methodology to be used in connection with evidentiary hearings that are to be undertaken to, among other things, determine a settlement of past accounts and refund liability. On July 25, 2001, FERC ordered that refunds may be due from sellers who engaged in transactions in the California markets between October 2, 2000, and June 20, 2001, including PG&E ET-Power and established a methodology to determine what refunds and payments were due for the defined refund period and defined markets. On December 19, 2001, and May 15, 2002 the FERC issued decisions purporting to clarify its earlier orders. Hearings before an administrative law judge were held in 2002, after which the judge issued proposed findings on December 12, 2002. The proposed findings indicated that PG&E ET owed refunds to the California Independent System Operator (ISO) of $9.6 million after crediting the amount that the ISO owed it for past sales. According to the December 12, 2002 findings, PG&E ET is also owed $4.8 million by the California Power Exchange, which is in bankruptcy. These figures were preliminary pending the appeals filed with the FERC on the administrative law judge’s proposed findings. On March 26, 2003, the FERC issued its order on the appeals. The FERC affirmed the administrative law judge’s findings, but adopted an alternative method to calculate the gas price element which will increase the amount ET-Power will owe. The FERC has deferred the settlements and recalculations until it rules on request for rehearing of its March 26, 2003, decision.

In addition on November 20, 2002, the FERC opened a second phase of its investigation of all wholesale sellers of electricity in California. It authorized 100 days of discovery relating to market manipulation in the period of January 1, 2000 through June 20, 2001. This discovery period ended on February 28, 2003. PG&E ET received and responded to discovery in the proceeding. Parties filed supplemental evidence of market manipulation on March 3, 2003, and responses on March 20, 2003. The FERC indicated on its March 26, 2003, order that review of the additional allegation is ongoing, and that depending on the outcome of the FERC’s review, the FERC may initiate one or more additional enforcement actions against entities found to have committed market manipulation in violation of the ISO and PX tariffs. The proposed remedy in such a proceeding would be the disgorgement of profits by those entities who are found to have violated one or both of the tariffs. Any such company-specific disgorgement or other appropriate remedies would be in addition to the refunds associated with the mitigated market methodology and could apply to conduct both prior to the refund period and during the refund period. PG&E NEG believes that the ultimate outcome of this matter will not have a material adverse effect on PG&E NEG’s financial condition or results of operations.

Natural Gas Royalties Litigation — This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including PG&E GTN. The cases were consolidated for pretrial purposes in the U.S. District Court, for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998. Under procedures established by the False Claims Act, the United States (acting through the Department of Justice (DOJ)) is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases. The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) mismeasured the volume and heating content of natural gas produced from federal or Indian leases.

As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases. The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and expenses associated with the litigation. PG&E NEG believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation. PG&E NEG believes that it is reasonably possible that it could incur a loss, but it is not able to determine the amount of such loss and, therefore, whether in light of the recent deterioration of PG&E NEG’s financial condition, such loss would have a material adverse effect on PG&E NEG’s financial condition or results of operations.

Asbestos Litigation — Pursuant to an Asset Purchase Agreement dated as of August 5, 1997, USGenNE agreed to indemnify New England Power Company (NEPCo) for certain losses. Such losses included claims arising from certain conditions on the site of the generation assets USGenNE purchased under the Asset Purchase Agreement. Several parties have filed suit or indicated that they may file suit against NEPCo for damages they claim arose out of exposure to asbestos fibers, which exposure allegedly took place while working at one or more of the generation assets that USGenNE purchased from NEPCo. Under the Asset Purchase Agreement USGenNE may be required to indemnify NEPCo for some or all of these claims. NEPCO has asserted its indemnity rights as to nine such cases, six of which have been resolved by NEPCO without payment to the plaintiff. The others are pending. PG&E NEG believes that the ultimate outcome of this litigation will not have a material adverse effect on PG&E NEG’s financial condition or results of operations.

Wholesale Standard Offer Service — USGenNE acquired from NEPCo and Narragansett Electric Company (Narragansett) certain generation assets in New England. As part of the acquisition, USGenNE entered into certain Wholesale Standard Offer Service Agreements (WSOS Agreements) with NEPCo’s distribution affiliates. A dispute has arisen over the party responsible for certain power pool imposed charges including NEPOOL and ISO-New England expenses and uplift charges. The distribution companies are currently paying the charges under a temporary agreement. The agreement allows either party to initiate proceedings to decide cost allocation issues. In a letter dated August 31, 2001, the distribution companies informed USGenNE that they are invoking the dispute resolution provisions of the WSOS Agreements and that they will seek reimbursement for these costs incurred under the temporary agreement along with a ruling that under the WSOS Agreements these costs should be imposed on USGenNE going forward. On March 27, 2002, the parties formally commenced arbitration. Hearings have been completed to date. NEPCo has incurred approximately $30 million for these power pool costs. Because of changes in the market rules that are to become effective, it is not possible to estimate going forward costs. The WSOS Agreements will expire at the end of 2004 and 2009.

In addition, the FERC has recently adopted a standard market design for New England, changing some of the products and costs associated with those products for market participants. There is another dispute between the distribution companies and USGenNE regarding responsibility for certain of these costs, including without limitation congestion charges, under the WSOS Agreements. USGenNE and the distribution companies are discussing entering into another temporary agreement under which the distribution companies would pay these costs, subject to a right to seek recovery of those payments in arbitration. USGenNE estimates that the going forward costs for the balance of the WSOS Agreements, were the distribution companies to prevail, would be approximately $19 million.

Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of this litigation may have a material adverse effect on PG&E NEG’s financial condition or results of operations.

Shaw Litigation — On August 13, 2001, Harquahala entered into an Engineering Procurement and Construction Contract (“EPC”) with the Shaw Group Inc. (“Shaw”) to design, procure materials and equipment for, and construct the Harquahala generating facility. In addition, during July of 2001 Harquahala

entered into a contract (the “Power Island Supply Contract”) with Siemens Westinghouse Power Corporation (Siemens), pursuant to which Siemens was to supply the thermal island equipment for the facility. The contract was subsequently assigned by Harquahala to Shaw, although Harquahala retained the obligation to make payments to Siemens following the assignment. Shaw directed Harquahala to withhold funds from Siemens. Siemens alleged that if Harquahala withheld such funds, it would be a default under the Power Island Supply Contract. When Harquahala declined to do so, Shaw alleged that such failure to withhold funds from Siemens as directed by Shaw constituted a breach of the EPC contract.

On November 13, 2002, Harquahala commenced an arbitration against Shaw seeking a declaration that it is not obligated to withhold payments from Siemens based upon Shaw’s alleged back charges or improperly documented warranty claims. Harquahala Generating Company, LLC v. The Shaw Group, Inc. et al., American Arbitration Association Case No. 161100085102. On or around December 4, 2002, Shaw filed a counterclaim for the value of certain change order requests. Shaw’s counterclaim seeks approximately $21.5 million and an extension of time by which to complete the facility. The most significant elements of the counterclaim are: a change order involving productivity losses that Shaw alleges resulted from the issuance by PG&E NEG of an 8-K in October 2002, detailing its financial condition; the acceleration of certain payments; a change order associated with the Siemens cover lift; and a change order associated with Siemens heat recovery steam generator assembly. The parties are now in the process of selecting arbitrators.

In a related proceeding, on January 6, 2003, Siemens commenced an arbitration proceeding against Harquahala seeking payment of approximately $5 million allegedly due under its July 2001 agreement with Harquahala to supply the thermal island equipment for its facility, plus all additional amounts that subsequently became due but are not paid as well as interest and arbitration costs and fees. Siemens Westinghouse Power Corporation v. Harquahala Generating Company, LLC, American Arbitration Association. Harquahala has withheld the amounts from Siemens at the direction of Shaw, to which the contract was assigned, based on Shaw’s assertion that Siemens has failed to perform in accordance with the terms of its July 2001 contract. The parties have agreed, in principle, to consolidate the proceedings.

On August 13, 2001, Covert Generating Company signed an EPC contract with Shaw respecting the Covert generating facility. On November 27, 2002, Shaw commenced an arbitration against Covert Generating Company claiming that it was entitled to approximately $23.6 million for certain change order requests. The Shaw Group Inc., et al. v. Covert Generating Company, LLC, American Arbitration Association Case No. 16Y1100090602. In addition, Shaw is also seeking an extension of time to complete the project. The parties are now in the process of selecting arbitrators.

At the time Harquahala and Covert signed their EPC contracts with Shaw, NEG Construction Finance Company, LLC (“CFC”) and PG&E NEG entered into related agreements pertaining to, among other things, the sharing of cost overruns in connection with the Covert and Harquahala facilities. On December 13, 2002, Shaw filed a lawsuit against each of these two parties as well as Harquahala and Covert. The Shaw Group, Inc. et al. v. PG&E National Energy Group, Inc., et al., United States District Court for the District of Delaware, Case No. 02-1676 GMS. Shaw alleges in its complaint that it has not received adequate assurances of payments from defendants and it seeks a declaration that, among other things, it is relieved of its obligations to perform under the EPC contracts and its agreements with CFC and PG&E NEG. Along with its complaint, Shaw filed a Motion for Expedite Declaratory and Injunctive Relief. At the end of December 2002, defendants filed oppositions to Shaw’s motion as well as motions to dismiss Shaw’s complaints. In addition, Societe Generale (as administrative agent for the project lenders) has filed a Motion to Intervene and a separate Opposition to Shaw’s Motion. On February 11, 2003, Shaw amended its complaint to seek to prevent PG&E NEG and its affiliates from turning over to the lenders the Covert and Harquahala projects, which turnover is one component of PG&E NEG’s restructuring. On March 13, 2003, Shaw purportedly voluntarily withdrew its pending action without prejudice. Covert, Harquahala and their lenders opposed this dismissal.

On March 16, 2003, Shaw purported to terminate the EPC contracts. On March 18, 2003, the lenders filed a claim for damages against Shaw naming Covert and Harquahala as nominal defendants.

Subsequent negotiations resulted in the execution, on or about April 10, 2003, of a non-binding term sheet outlining the principles for a settlement of all pending disputes among Shaw, Covert, Harquahala, PG&E NEG and CFC related to the Covert and Harquahala projects.

Under the terms of the proposed settlement PG&E NEG will pay $32.5 million to Shaw, the engineering procurement and construction contracts will be increased in the aggregate by $65 million (the balance funded by the lenders), the completion deadlines will be extended, the cost-sharing agreements and related guarantees will be terminated, and PG&E NEG completion guarantees to the lenders will be released. The parties are now negotiating definitive agreements. PG&E NEG has recognized a charge of $32.5 million for these anticipated costs in the first quarter.

Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of all of this litigation may have a material adverse effect on PG&E NEG’s financial condition or results of operations. See Note 6, “Impairment of Shaw Settlement Charges”, for information regarding this matter.

Mitsubishi Litigation — Mitsubishi Power Systems, Inc. (“MPS”) has alleged a default under its contract for the sale and purchase of gas turbines and other equipment for failure to pay $14 million. PG&E NEG’s subsidiary has disputed this default notice because the payments were not due until January 2003 and July 2003. MPS terminated the contract for this alleged default on November 21, 2002. Although PG&E NEG does not agree that MPS had the right to do so, neither PG&E NEG nor any of its affiliates intended to challenge the termination. On January 31, 2003, PG&E NEG paid $4.5 million of the $14 million.

On May 7, 2003, Mitsubishi Heavy Industries, Inc. (“MHI”) filed suit in the United States District Court for the District of Maryland against PG&E National Energy Group, LLC (“NEG LLC”) and PG&E National Energy Group Construction Company, LLC (“Construction”). Mitsubishi Heavy Industries, Inc. v. PG&E National Energy Group. The defendants have not yet been served. In its complaint, MHI alleges damages totaling approximately $300 million under the turbine purchase agreement and related contracts. MHI’s claims arise from a dispute between the parties to a turbine purchase agreement regarding payments allegedly past due from Construction in respect of reservation fees ($9.5 million) and gas generator equipment manufacture ($30 million). MPS also requested that PG&E NEG cash collateralize its $75 million guarantee issued in connection with the turbine purchase agreement. PG&E NEG and Construction have maintained (and will maintain in defense of MHI’s claims) that no amounts were or are due.

Trading Companies Employee Claims — A number of employees have commenced judicial or administrative proceedings or have threatened to commence proceedings against a variety of NEG subsidiaries. They claim that they are entitled to various types of bonuses and, in some cases, severance and other benefits. The aggregate amount of these claims is approximately $43 million. Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of all of this litigation may have a material adverse effect on PG&E NEG’s financial condition or results of operations.

USGen New England — In September 1998, USGenNE acquired the non-nuclear generating assets of the New England Electric System (NEES) for approximately $1.8 billion. These assets included:


	•	2,344 megawatts (MW) of coal- and oil-fired power plants in Massachusetts;

	•	1,166 MW of hydroelectric facilities in New Hampshire, Vermont and Massachusetts;

	•	495 MW of gas-fired power plants in Rhode Island;

	•	above-market power purchase agreements with support payments provided by NEES for the first nine years;

	•	gas pipeline transportation contracts; and

	•	transition wholesale load contracts known as Standard Offer Agreements.

Consistent with its previously announced strategy to dispose of certain merchant assets, in December 2002, the Board of Directors of PG&E Corporation approved management’s plans for the proposed sale of USGenNE. Under the provisions of SFAS No. 144, the equity of USGenNE has been accounted for as an asset held for sale at December 31, 2002. This requires that the asset be recorded at the lower of fair value, less costs to sell, or book value. Based on the current estimated fair value (based on the estimated proceeds) of a sale of USGenNE, PG&E NEG recorded a pretax loss of $1.1 billion, in the fourth quarter of 2002. PG&E NEG recorded an additional pretax loss on disposal of $23 million in the first quarter 2003. It is anticipated that arrangements for the disposition of the USGenNE assets will be made during 2003. However, as a result of required regulatory approval by the FERC, it is anticipated that any disposals will not be consummated until 2004. The operating results from USGenNE are being reported as discontinued operations in the Consolidated Financial Statements of PG&E NEG and subsidiaries for the three months ended March 31, 2003 and 2002. Also under the provisions of SFAS No. 144, no depreciation has been recorded on the restated assets.

Mountain View — On September 17 and 28, 2001, PG&E NEG purchased Mountain View Power Partners, LLC and Mountain View Power Partners II, LLC, respectively (collectively referred to as Mountain View) from SeaWest WindPower, Inc. These companies own 44- and 22-MW wind energy projects, respectively, near Palm Springs, California. PG&E NEG contracted with SeaWest for the operation and maintenance of the wind units. Total consideration for these two companies was $92 million. The two companies were merged on October 1, 2002. The power is sold to the California Department of Water Resources (DWR) under a 10-year contract.

In December 2002, the Board of Directors of PG&E Corporation approved the sale of Mountain View. On December 18, 2002, a subsidiary of PG&E NEG entered into an agreement to sell Mountain View to Centennial Power, Inc. The sale occurred on January 3, 2003. PG&E NEG received $102 million in proceeds for the sale of Mountain View resulting in a $19 pre-tax million gain.

Under the provisions of SFAS No. 144 Mountain View is accounted for as an asset held for sale at December 31, 2002. The operating results from Mountain View are being reported as discontinued operations in the Consolidated Financial Statements of PG&E NEG and subsidiaries at December 31, 2002.

ET Canada — On March 18, 2003, PG&E Energy Trading-Gas Corporation (ET-Gas), a subsidiary of PG&E NEG, completed the sale of 100% of the stock of PG&E Energy Trading, Canada Corporation (ET Canada) to Seminole Canada Gas Company, a Nova Scotia unlimited liability company (Seminole). Seminole transferred approximately $86 million at closing to ET-Gas and several of its affiliates, representing the purchase price and the return of collateral posted by ET-Gas and ET Canada to support ET Canada’s

energy trading transactions, plus interest. Most of the proceeds were used to repay principal and interest on an outstanding loan of $76 million to another affiliate.

Seminole also has agreed within 30 days after the closing to replace certain letters of credit issued to support ET Canada’s energy trading transactions and to obtain the release of ET-Gas and its affiliates, including PG&E GTN and PG&E NEG from obligations under guarantees issued for the same reasons. Seminole has indemnified ET-Gas for any liability under the letters of credit or the guarantees. As previously disclosed, in the fourth quarter of 2002, PG&E NEG recorded a $25 million pre-tax loss, on the anticipated disposition of ET Canada. In the first quarter of 2003, an additional loss on disposal was recorded of $3 million pre-tax.

The following table reflects the operating results of the combined USGenNE, Mountain View and ET Canada before reclassification to discontinued operations for the three months ended March 31, 2003 and 2002 (in millions):

The following table reflects the components of assets and liabilities held for sale of USGenNE before reclassification to discontinued operations at March 31, 2003 and the combined USGenNE, Mountain View and ET Canada at December 31, 2002. (in millions):


⁽¹⁾	Includes impairment charges made against property, plant and equipment.


⁽²⁾	USGenNE receives payments from a subsidiary of NEES, related to the assumption of power supply agreements, which are payable monthly through January 2008. The long-term receivables are valued at the present value of the scheduled payments using a discount rate that reflects NEES’ credit rating on the date of acquisition.

⁽³⁾	Commitments contained in the underlying Power Purchase Agreements (PPAs) by USGenNE, gas commodity and transportation agreements (collectively, the Gas Agreements), and Standard Offer Agreements, acquired by USGenNE in September 1998, were recorded at fair value, based on management’s estimate of either or both the gas commodity and gas transportation markets and electric markets over the life of the underlying contracts, discounted at a rate commensurate with the risks associated with such contracts. Standard Offer Agreements reflect a commitment to supply electric capacity and energy necessary for certain affiliates to meet their obligations to supply fixed-rate service. PPAs and Gas Agreements are amortized on a straight-line basis over their specific lives. The Standard Offer Agreements are amortized using an accelerated method since the decline in value is greater in earlier years due to increasing contract pricing terms designed to reduce demand for our supply service over time.

Included in the assets and liabilities held for sale summary above, are certain amounts paid to USGenNE related to the assumption of power supply agreements and certain purchase obligations assumed by USGenNE from the acquisition that occurred in 1998.

Consolidation and Impairment of Attala Generating Company LLC — On May 7, 2002, Attala Generating Company LLC (Attala Generating), an indirect subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back a 526 MW generation facility (the Facility) in Mississippi to two third-party special-purpose entities (SPEs). These entities funded the acquisition of their undivided interests in the Facility through proceeds from the issuance of debt and equity. The SPEs funded $103 million, or approximately 30 percent of the total fair value of the Facility on the transaction date, from the issuance of equity. The related transaction was accounted for as a lease because the owners of the SPEs had made an initial substantive residual equity capital investment that was intended to be at risk during the entire term of the lease.

During January 2003, the SPEs distributed cash to its equity holders, which resulted in the SPEs no longer meeting the substantive equity at risk criteria under current accounting requirements. PG&E NEG now consolidates the assets and liabilities of the SPEs.

The consolidation of the SPEs resulted in an increase in assets of $62 million, representing the estimated fair value of the Facility and related inventories, and debt of $237 million, representing the bonds issued to finance the sale-leaseback transaction. As a result of the SPEs excess of liabilities over assets, a pre-tax charge to earnings of $175 million was recorded in the first quarter of 2003.

In January 2003, the FASB issued Interpretation No. 46, “Consolidation of Variable Interest Entities” (FIN 46). See Note 1, “General — Adoption of New Accounting Policies,” for a more complete description of FIN 46. PG&E NEG currently is evaluating the impacts of FIN 46’s initial recognition, measurement, and disclosure provisions on its Consolidated Financial Statements when these requirements become effective by the beginning of the third quarter of 2003.

PG&E NEG believes that, upon the adoption of FIN 46, it will not be required to continue to consolidate the SPEs associated with the sale-leaseback of the Facility since it has neither an equity investment nor a significant variable interest in the SPEs. Depending on the method of adopting FIN 46 by PG&E NEG, either the difference between the book values of the SPEs’ assets and liabilities will be recognized through earnings or first quarter 2003 financial statements will be restated to eliminate the impact of initially consolidating the SPEs. Future earnings may also be impacted by the accrual of any probable payments under the Attala guarantee arrangement disclosed in Note 4 of the Notes to the Consolidated Financial Statements.

Shaw Settlement Charges — Harquahala generating facility, owned by Harquahala, is a 1,092-megawatt plant in Tonopah, Arizona, with about 88 percent of the construction complete. Covert generating facility,

owned by Covert, is a 1,170-megawatt plant in Covert, Michigan, with about 84 percent of construction complete. The equity in Covert and Harquahala is owned by GenHoldings I, LLC (GenHoldings), a subsidiary of PG&E NEG. On August 13, 2001, Harquahala and Covert entered into engineering procurement and construction contracts (EPCs) with Shaw to design, procure materials and equipment for, and construct these generating facilities.

During November and December 2002, Harquahala commenced arbitration against Shaw seeking a declaration that it was not obligated to withhold payments from a certain third party connected with the construction of the facility. Subsequently, Shaw commenced arbitration against Covert and Harquahala to recover the value of certain change order requests. In addition, Shaw filed a lawsuit against Harquahala, Covert, PG&E NEG, and NEG Construction Finance Company, LLC (CFC), alleging that it had not received adequate assurance of payment from PG&E NEG.

Mantua Creek Project: The Mantua Creek project is a nominal 897 MW combined cycle merchant power plant located in the Township of West Depford, New Jersey. Due to liquidity concerns, PG&E NEG could no longer provide equity contributions to the project and beginning in the fourth quarter of 2002, began to suspend or terminate contracts with vendors. At December 31, 2002, PG&E NEG wrote off capitalized development and construction costs of $257 million and established an additional accrual of $22 million for charges and associated termination costs. For the period ending March 31, 2003, various termination cost accruals were adjusted as settlements occurred resulting in an approximately $8 million reduction in impairment expense.

PG&E NEG is in the process of reducing and unwinding its trading positions. Additionally, asset hedge positions associated with the merchant plants will either remain with the assets or be terminated. PG&E NEG has significantly reduced its energy trading operations in an ongoing effort to raise cash and reduce debt. PG&E NEG’s objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer or abandonment process. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations.

At March 31, 2003, PG&E NEG had cash flow hedges of varying durations associated with commodity price risk, interest rate risk and foreign currency risk, the longest of which extend through December 2011, March 2014, and December 2004, respectively.

The amount of commodity hedges included in Accumulated Other Comprehensive Income or Loss (OCI), net of taxes, at March 31, 2003, was a loss of $55 million. The amount of interest rate hedges included in OCI, net of taxes, at March 31, 2003, was a loss of $76 million. The amount of foreign currency hedges included in OCI, net of taxes, at March 31, 2003, was a loss of $2 million.

PG&E NEG’s net derivative losses included in OCI at March 31, 2003, were $133 million, of which approximately $69 million is expected to be reclassified to earnings within the next 12 months based on the

contractual terms of the contracts or the termination of the hedge positions. The actual amounts reclassified from OCI to earnings will differ as a result of market price changes.

The schedule below summarizes the activities affecting accumulated other comprehensive income (loss), net of tax, from derivative instruments (in millions):

Normally, most non-trading activity earnings are recognized on an accrual basis as revenues are earned and as expenses are incurred. For example, the effective portion of contracts accounted for as cash flow hedges have no mark-to-market effect on earnings; these contracts are presented on a mark-to-market basis on the balance sheet in PRM assets and liabilities and OCI. Other non-trading contracts are exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception and thus have no mark-to-market effect on earnings.

Cash flow hedge accounting was discontinued for commodity cash flow hedges on January 1, 2003. Accordingly, such non-trading activities affect PG&E NEG’s earnings on a mark-to-market basis. PG&E NEG recognizes the prospective changes in fair value relating to commodity hedges and the ineffective portion of the fair value of all other hedges in earnings. PG&E NEG also has certain derivative contracts that, while they are meant for non-trading purposes, do not qualify for cash flow hedge accounting or for the normal purchases and sales exception to SFAS No. 133. These derivatives are reported in earnings on a mark-to-market basis. These contracts primarily consist of those derivative commodity contracts for which normal purchases and sales treatment was disallowed upon PG&E NEG’s implementation of DIG C15 and C16 effective April 1, 2002 .

PG&E NEG’s pre-tax earnings for the period ended March 31, 2003, include gains of $50 million related to commodity hedges which were previously deferred in OCI and were reclassified to earnings, after it became probable that the forecasted transactions will not occur.

Unrealized gains and losses from trading activities, including the reversal of unrealized gains and losses previously recognized on contracts that go to settlement or delivery, are presented on a net basis in operating revenues. Realized gains and losses from trading activities also are presented on a net basis in operating revenues, beginning in the third quarter of 2002, as more fully described in Note 1.

Gains and losses on trading contracts affect PG&E NEG’s gross margin in the accompanying PG&E NEG Consolidated Statements of Operations on an unrealized, mark-to-market basis as the fair value of the forward positions on these contracts fluctuate. Settlement or delivery on a contract is generally not an event that results in incremental net income recognition, because the profit or loss on a contract is recognized in income on an unrealized, mark-to-market basis during the periods before settlement occurs.

Gains and losses on trading contracts affect PG&E NEG’s cash flow when these contracts are settled. Net realized gains reported in the table below primarily reflect the net effect of contracts that have been settled in cash. Net realized gains also include certain non-cash items, including amortization of option premiums that were paid or received in cash in earlier periods but are considered realized when the related options are exercised or expire.

PG&E NEG’s net gains (losses) on trading activities are as follows (in millions):

PRM assets and liabilities on the accompanying PG&E NEG Consolidated Balance Sheets reflect the aggregation of the fair values of outstanding contracts. These fair values are calculated on a mark-to-market basis for contracts that will be settled in future periods. PRM assets and liabilities at March 31, 2003, include amounts for trading and non-trading activities, as described below (in millions).

Non-trading activities include certain long-term contracts that are not included in PG&E NEG’s trading portfolio but that, due to certain pricing provisions and volumetric variability, are unable to receive hedge accounting treatment or the normal purchases and sales exception, as outlined by interpretations of SFAS No. 133. PG&E NEG has certain other non-trading derivative commodity contracts for the physical delivery of purchases and sales quantities transacted in the normal course of business. These other non-trading activities include contracts that are exempt from SFAS No. 133 fair value requirements under the normal purchases and sales exemption, as described previously. Although the fair value of these other non-trading contracts is not required to be presented on the balance sheet, revenues and expenses generally are recognized in income using the same timing and basis as are used for the non-trading activities accounted for as cash flow hedges. Hence, revenues are recognized as earned and expenses are recognized as incurred.

Credit risk is the risk of loss that PG&E NEG would incur if counterparties failed to perform their contractual obligations (these obligations are reflected as Accounts receivable -Trade, net; notes receivable included in Other noncurrent assets — Other; Price Risk Management (PRM) assets; and Assets held for sale on the Consolidated Balance Sheet). PG&E NEG conducts business primarily with customers or vendors, referred to as counterparties, in the energy industry. These counterparties include other investor-owned utilities, municipal utilities, energy trading companies, financial institutions, and oil and gas production companies located in the United States and Canada. This concentration of counterparties may impact PG&E

NEG’s overall exposure to credit risk because its counterparties may be similarly affected by economic or regulatory changes, or other changes in conditions.

PG&E NEG manages its credit risk in accordance with the PG&E Corporation Risk Management Policy. This establishes processes for assigning credit limits to counterparties entering into agreements with significant exposure to PG&E NEG. These processes 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 NEG takes immediate action to reduce the exposure, or obtain additional collateral, or both. Further, PG&E NEG relies heavily on master agreements that require the counterparty to post security, referred to as credit collateral, in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

PG&E NEG calculates gross credit exposure for each counterparty as the current mark-to-market value of the contract (that is, the amount that would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, prior to the application of the counterparty’s credit collateral.

During the three months ended March 31, 2003, PG&E NEG’s credit risk has decreased primarily due to current terminations with counterparties. PG&E NEG recognized no losses due to the contract defaults or bankruptcies of counterparties during the three months ended March 31, 2003.

At March 31, 2003, PG&E NEG had one single counterparty that represented greater than 10 percent of PG&E NEG’s net credit exposure with a net credit exposure amount of $50 million. At December 31, 2002, PG&E NEG had no single counterparty that represented 10 percent of PG&E NEG’s net credit exposure.

The schedule below summarizes PG&E NEG’s credit risk exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), at March 31, 2003, and December 31, 2002 (in millions):


⁽¹⁾	Gross credit exposure equals mark-to-market value, notes receivable, and net (payables) receivables where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity, model or credit reserves.

⁽²⁾	Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit).

At March 31, 2003, approximately $39 million, or 10 percent of PG&E NEG’s net credit exposure was to entities that had credit ratings below investment grade. At December 31, 2002, approximately $172 million, or 21 percent of PG&E NEG’s net credit exposure was to entities that had credit ratings below investment grade. Investment grade is determined using publicly available information, i.e. rated at least Baa3 by Moody’s and BBB- by S&P. If the counterparty provides a guarantee by a higher rated entity (e.g., its parent), the credit rating determination is based on the rating of its guarantor. At March 31, 2003, approximately $92 million, or 23 percent of PG&E NEG’s net credit exposure was with counterparties that were not rated. At December 31, 2002, approximately $65 million or 8 percent of PG&E NEG’s net credit exposure was with counterparties that were not rated. Most counterparties with no credit rating are governmental authorities which are not

rated, but which PG&E NEG has assessed as equivalent to investment grade. Other counterparties with no credit rating are subject to an internal assessment of their credit quality and a credit rating designation.

PG&E NEG’s regional concentrations of credit exposure are to counterparties that conduct business primarily throughout North America.

PG&E NEG has two reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, and how information is reported to PG&E NEG key decision makers. The first business segment is composed of PG&E NEG’s Integrated Energy and Marketing Activities, principally the generation and energy trading operations, which are managed and operated in an integrated manner. The second business segment is PG&E NEG’s Interstate Pipeline Operations.

Segment information for the three months ended March 31, 2003, and 2002 was as follows (in millions):


(1)	Inter-segment revenues are recorded at market prices for services provided.

(2)	Includes PG&E NEG holding company costs, principally unallocated interest and fee related expense, elimination entries, and other miscellaneous ventures not associated with core business segments.

(3)	Prior periods amounts have been restated to reflect the reclassification of USGenNE, Mountain View, and ET Canada operating results to discontinued operations.

(4)	Operating revenues and operating expenses reflect the adoption of a new accounting policy in the third quarter of 2002 implementing a retroactive change from gross to net method of reporting revenues and expenses on trading activities. The amounts for trading activities for this period have been reclassified to conform with the new presentation.

PG&E National Energy Group, Inc. (PG&E NEG) is an integrated energy company with a focus on power generation and natural gas transmission in North America. PG&E NEG and its subsidiaries have integrated their generation, development and energy marketing and trading activities.

PG&E NEG was incorporated on December 18, 1998, as a subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E NEG is an indirect subsidiary of PG&E Corporation. PG&E NEG and its subsidiaries are principally located in the United States and Canada and are currently engaged in power generation, and natural gas transmission. PG&E NEG’s principal subsidiaries include:


	•	PG&E Generating Company, LLC and its subsidiaries, collectively referred to as PG&E Gen;

	•	PG&E Energy Trading Holdings Corporation and its subsidiaries, collectively referred to as PG&E ET;

	•	PG&E Gas Transmission Corporation and its subsidiaries, collectively referred to as PG&E GTC, which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively referred to as PG&E GTN) which includes North Baja Pipeline, LLC,

As a result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade PG&E NEG’s and its affiliates’ credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling $2.7 billion, but this debt is non-recourse to PG&E NEG. PG&E NEG, its subsidiaries, and their lenders have been engaged in discussions to restructure PG&E NEG’s and its subsidiaries’ debt obligation and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy Code. Although PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of PG&E NEG and its subsidiaries. Absent a negotiated agreement, the lenders may exercise their default remedies or force PG&E NEG and certain of tis subsidiaries into an involuntary proceeding under the Bankruptcy Code. Notwithstanding the status of current negotiations, PG&E NEG and certain of its subsidiaries also may elect to voluntarily seek protection under the Bankruptcy Code as early as the second quarter 2003. The factors affecting PG&E NEG’s business causing these defaults and the principal actions being taken by PG&E NEG are discussed later in this MD&A and in Note 3 of the Notes to the Consolidated Financial Statements.

During the fourth quarter of 2002, PG&E NEG and certain subsidiaries agreed to sell or sold certain assets, abandoned other assets, and significantly reduced energy trading operations. PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities. As a result, PG&E NEG expects to incur substantial charges to earnings in 2003 as it restructures its operations.


	•	Interstate Pipeline Operations, or the Pipeline Business; and

	•	Integrated Energy and Marketing, or the Energy Generation Business.


	•	Types of customers;

	•	Methods of distribution;

	•	Regulatory environment; and

	•	How information is reported to and used by PG&E NEG key decision makers.

These two reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdiction.

Financial information about each reportable operating segment is provided in this MD&A and in Note 8 of the Notes to the Consolidated Financial Statements.

This discussion and analysis explains the general financial condition and the results of operations of PG&E NEG and its subsidiaries including:


	•	Factors that affect each business;

	•	A comparison of revenues and expenses and why they changed between periods;

	•	The expected sources and uses of cash between periods;. and

	•	How all of this along with related commitments and contingencies affects overall financial condition.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein. Further, this quarterly report on Form 10-Q should be read in conjunction with the PG&E NEG 2002 Annual Report on Form 10K, as amended.

In its Pipeline Business segment, PG&E NEG owns, operates and develops natural gas pipeline facilities, including the pipelines owned by PG&E GTN and an interest in the Iroquois pipeline.

In the Generation Business segment, PG&E NEG engages in the generation of electricity in the continental United States. As of March 31, 2003, PG&E NEG had ownership or leasehold interests in 16 operating generating facilities with a net generating capacity of 1,476 megawatts (MW), as follows:

PG&E NEG provides operating and/or management services for 14 of these 16 owned and leased generating facilities. Plant operations are focused on maximizing power generation ability during peak energy price hours, improving operating efficiencies and minimizing operating costs while placing a heavy emphasis on safety standards, environmental compliance and plant flexibility.

These generating facilities sell all or a majority of their electrical capacity and output to one or more third parties under long-term power purchase agreements tied directly to the output of that plant.

PG&E NEG holds interests in these projects through indirect subsidiaries and typically manages and operates these facilities through an operation and maintenance agreement and/or a management services agreement. These agreements generally provide for management, operations, maintenance and administration for day-to-day activities, including financial management, billing, accounting, public relations, contracts,

The revenues generated from long-term power sales agreements usually consist of two components: energy payments and capacity payments. Energy payments are typically based on the facility’s actual electrical output and capacity payments are based on the facility’s total available capacity. Energy payments are made for each kilowatt-hour of energy delivered, while capacity payments, under most circumstances, are made whether or not any electricity is delivered. However, capacity payments may be reduced if the facility does not attain an agreed availability level. The average life of a power sales agreement is 15 years.

This quarterly report or 10Q, including 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 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,” “could,” “should,” “would,” “may,” and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements.

Although PG&E NEG is 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 historical results or those expressed or implied by the forward-looking statements, or from historical results, include:

Potential Bankruptcy Filing. The timing and manner in which bankruptcy proceedings involving PG&E NEG and certain of its subsidiaries commence will be affected by:


	•	the outcome of PG&E NEG’s negotiations with its lenders under various credit facilities, as well as with representatives of the holders of PG&E NEG’s Senior Notes, to restructure PG&E NEG and its subsidiaries’ indebtedness and commitments;

	•	The inability of PG&E NEG, its merchant asset and other subsidiaries, including USGen New England, Inc. (USGenNE), to maintain sufficient liquidity necessary to meet their commodity and other obligations;

	•	The inability of USGenNE to comply with future environmental regulations and the impact such non-compliance would have on USGenNE’s ability to operate its generating projects, particularly the Salem Harbor and Brayton Point power plants.

Efforts to Restructure Operations. PG&E NEG’s future results of operation and financial condition will be affected by the success of its efforts to restructure its operations, including:


	•	the extent to which PG&E NEG incurs further charges to earnings as a result of the abandonment, sale or transfer of assets or termination of contractual commitments, whether such transactions occur in connection with restructuring of PG&E NEG’s indebtedness or otherwise;

	•	any potential charges to income that would result from the reduction and potential discontinuance of PG&E NEG’s energy trading and marketing operations including tolling transactions; and

	•	the impact of layoffs and loss of personnel.

Current Conditions in the Energy Markets and the Economy. PG&E NEG’s future results of operation and financial condition will be affected by changes in energy markets, changes in the general economy, wars, embargoes, financial markets, interest rates, other industry participant failures, the markets’ perception of energy merchant facilities and other factors.

Actions of Counterparties. PG&E NEG’s future results of operation and financial condition may be affected by:


	•	the extent to which counterparties demand collateral in connection with PG&E ET’s trading and nontrading activities and the ability of PG&E NEG and its subsidiaries to meet the liquidity calls that may be made; and

	•	the extent to which tolling agreements and other contracts are terminated and the amount of any termination damages they may seek to recover from PG&E NEG as guarantor.

Accounting and Risk Management. PG&E NEG’s future results of operation and financial condition may be affected by:


	•	the effect of new accounting pronouncements;

	•	changes in critical accounting estimates;

	•	volatility in income resulting from mark-to-market accounting, or changes in mark-to-market methodologies;

	•	the extent to which the assumptions underlying critical accounting estimates, mark-to-market accounting, and risk management programs are not realized;

	•	the volatility of commodity fuel and electricity prices and the effectiveness of risk management policies and procedures designed to address volatility; and

	•	the ability of counterparties to satisfy their financial commitments and the impact of counterparties’ nonperformance on PG&E NEG’s liquidity.


	•	legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries; and

	•	heightened regulatory and enforcement agency focus on the merchant energy business including investigations into “wash” or “round-trip” trading, specific trading strategies and other industry issues, with the potential for changes in industry regulations and in the treatment of PG&E NEG by state and federal agencies.

Pending Litigation and Environmental Matters. PG&E NEG’s future results of operation and financial condition may be affected by:


	•	the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;

	•	the outcome of pending litigation and environmental matters; and

	•	the outcome of the California Attorney General’s petition requesting revocation of PG&E Corporation’s exemption from the Public Utility Holding Company Act of 1935, and the effect of such outcomes, if any, on PG&E NEG.

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

PG&E NEG’s Consolidated Financial Statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. However, as a result of current liquidity concerns and restructuring discussions with PG&E NEG’s lenders, such realization of assets and liquidation of liabilities are subject to uncertainty.

During 2002, energy markets experienced several significant adverse changes including:


	•	Contractions and instability of wholesale electricity and energy commodity markets;

	•	Significant decline in generation margins (spark spreads) caused by excess supply and reduced demand in most regions of the United States;

	•	Loss of confidence in energy companies due to increased scrutiny by regulators, elected officials, and investors as a result of a string of financial reporting scandals;

	•	Heightened scrutiny by credit rating agencies prompted by these market changes and scandals which resulted in lower credit ratings for many market participants; and

	•	Resulting significant financial distress and liquidity problems among market participants leading to numerous financial restructurings and less market participation.

PG&E NEG was significantly impacted by these adverse changes in 2002. New generation came online while the demand for power was dropping. This oversupply and reduced demand created low spark spreads (i.e. the net of power prices less fuel costs) and depressed operating margins. These changes in the power industry have had a significant negative impact on the financial results and liquidity of PG&E NEG. Before July 31, 2002, most of the various debt instruments of PG&E NEG and its affiliates carried investment grade credit ratings assigned by Standard & Poor’s Ratings Group (S&P) and Moody’s Investors Service (Moody’s). Since July 31, 2002, these credit rating agencies have downgraded all of PG&E NEG’s debt facilities to below investment grade.

As a result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade PG&E NEG’s and its affiliates’ credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling $2.7 billion, but this debt is non-recourse to PG&E NEG. PG&E NEG, its subsidiaries, and their lenders have been engaged in discussions to restructure PG&E NEG’s and its subsidiaries’ debt obligations and other commitments since October 2002. No agreement has been reached yet and there can be no assurance that an agreement will be reached. Any restructuring agreement that may be reached would be implemented through a reorganization proceeding under Chapter 11 of the Bankruptcy Code. Although PG&E NEG and its subsidiaries are continuing their efforts to maximize cash and reduce liabilities, such efforts are not expected to restore the financial condition of PG&E NEG and its subsidiaries. Absent a negotiated agreement, the lenders may exercise their default remedies or force PG&E NEG and certain of its subsidiaries into an involuntary proceeding under the Bankruptcy Code. Notwithstanding the status of current negotiations, PG&E NEG and certain of its subsidiaries also may elect to voluntarily seek protection under the Bankruptcy Code as early as the second quarter 2003. The factors affecting PG&E NEG’s business causing these defaults and the principal actions being taken by PG&E NEG are discussed later in this MD&A and in Note 3 of the Notes to the Consolidated Financial Statements.

During the fourth quarter of 2002, PG&E NEG and certain subsidiaries agreed to sell or sold certain assets, abandoned other assets, and significantly reduced energy trading operations.

PG&E NEG and its subsidiaries are restructuring their operations to increase cash, reduce financial obligations, dispose of merchant plant facilities, and decrease energy trading operations. PG&E NEG’s objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer or abandonment. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations.

Asset transfers, sales or abandonments, liquidity issues and potential restructuring resulted in substantial charges in earnings in 2002. In addition to these 2002 charges, PG&E NEG and its subsidiaries has incurred and expects to incur additional substantial charges to earnings in 2003 primarily related to:


	•	The reduction in energy trading activities;

	•	The possible settlement of tolling arrangements (see discussion of tolling agreements in this MD&A under Commitments and Capital Expenditures — Tolling Agreements);

	•	A possible settlement under the Attala tolling agreement and related lease;

	•	Potential conversion of existing debt and equity funding commitments to new discounted obligations, including potential write-offs of deferred financing costs; and

	•	Further restructuring costs.

PG&E NEG’s and its subsidiaries’ guarantees fall into four broad categories:


	•	equity commitments;

	•	PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio, excluding tolling agreements;

	•	tolling agreements; and

	•	other guarantees.

PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.7 billion, but this debt is non-recourse to PG&E NEG. On November 14, 2002, PG&E NEG defaulted on the repayment of the $431 million 364-day tranche of its corporate revolving credit facility (Corporate Revolver). Loans and letters of credit outstanding as of March 31, 2003 under the two-year tranche of the Corporate Revolver was $258 million, $185 million of letters of credit and $73 million of loans. The default under the Corporate Revolver also constitutes a cross-default as of March 31, 2003, under (1) PG&E NEG’s Senior Notes ($1 billion outstanding), (2) its guarantee of a turbine revolving credit agreement ($205 million outstanding), and (3) its equity commitment guarantees for the GenHoldings credit facility ($355 million outstanding), for the La Paloma credit facility ($375 million outstanding) and for the Lake Road credit facility ($230 million outstanding). In addition, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under the Senior Notes. PG&E NEG currently does not have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.

GenHoldings Projects — GenHoldings, an indirect subsidiary of PG&E NEG, is obligated under its credit facility to make equity contributions to fund construction of the Harquahala, Covert and Athens generating projects. This credit facility is secured by these projects in addition to the Millennium generating facility. GenHoldings defaulted under its credit agreement in October 2002, by failing to make equity contributions to fund construction draws for the Athens, Harquahala and Covert generating projects. Although PG&E NEG has guaranteed GenHoldings’ obligations to make equity contributions of up to $355 million, PG&E NEG notified the GenHoldings’ lenders that it would not make further equity contributions on behalf of GenHoldings. In November and December 2002, the lenders executed waivers and amendments to the credit agreement under which they agreed to continue to waive, until March 31, 2003, the default caused by GenHoldings’ failure to make equity contributions.

As of March 21, 2003, the lenders executed a waiver letter extending to June 30, 2003, the waiver of GenHoldings’ Equity Default. In addition, the waiver letter also waives other existing defaults in order to permit the continued availability of loan facilities to fund construction and operation of the projects until such time as a transfer of the projects to the GenHoldings lenders may be completed. An event of default will occur if such transfer is not accomplished by such deadline. Such a default would trigger lender remedies, including the right to foreclose on Millennium, Harquahala, Athens, and Covert.

Lake Road and La Paloma Projects — In September 1999 and March 2000, Lake Road Generating Company, LP (Lake Road) and La Paloma Generating Company, LLC (La Paloma) entered into Participation Agreements to finance the construction of the two plants. In November 2002, Lake Road and La Paloma defaulted on their obligations to pay interest and swap payments. In addition, as a result of PG&E NEG’s downgrade to below investment grade by both S&P and Moody’s, PG&E NEG, as guarantor of certain debt obligations of Lake Road and La Paloma, became required to make equity contributions to Lake Road and La Paloma of $230 million and $375 million respectively. The lenders have accelerated all debt existing prior to December 11, 2002, including the guaranteed portion of the debt and made a payment under the PG&E NEG guarantee. Neither PG&E NEG, Lake Road nor La Paloma has sufficient funds to make these payments.

PG&E NEG and certain subsidiaries have provided guarantees as of March 31, 2003, to approximately 188 counterparties in support of PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio in the face amount of $2.2 billion. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully used at any time. As of March 31, 2003, PG&E NEG and its subsidiaries’ aggregate exposure under these guarantees was approximately $150 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.

At March 31, 2003, PG&E ET’s estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $96 million.

To date, PG&E ET has met those replacement security requirements properly demanded by counterparties and has not defaulted under any of its master trading agreements although one counterparty has alleged a default. No demands have been made upon the guarantors of PG&E ET’s obligations under these trading agreements. In the past, PG&E ET has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E ET or its counterparties have faced similar situations. There can be no assurance that PG&E ET can continue to negotiate acceptable arrangements in the current circumstances. PG&E NEG cannot quantify with any certainty the actual future calls on PG&E ET’s liquidity. PG&E NEG’s and its subsidiaries’ ability to meet these calls on their liquidity will vary with market price volatility, uncertainty with respect to PG&E NEG’s financial condition and the degree of liquidity in the energy markets. The actual calls for collateral will depend largely upon the ability to enter into forbearance agreements and pre- and early-pay arrangements with counterparties, the continued performance of PG&E NEG companies under the underlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of exposure, and the counterparties’ other commercial considerations.

PG&E ET has entered into tolling agreements with several counterparties under which at its discretion, it supplies the fuel to the power plants and then sells the plant’s output in the competitive market. Payments to the counterparties are reduced if the plants do not achieve agreed-upon levels of performance. The face amount of PG&E NEG’s and its subsidiaries’ guarantees relating to PG&E ET’s tolling agreements is approximately $600 million. The tolling agreements are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed primarily by PG&E NEG and secondarily by PG&E GTN for an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $175 million; and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty — Liberty has provided notice to PG&E ET that the ratings downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PG&E ET to replace the guarantee and post security in the amount of $150 million. PG&E ET has not posted such security. Liberty has the right to terminate the agreement and seek recovery of a termination payment. Under the terms of the guarantees to Liberty, Liberty has the right to terminate the agreement and seek recovery of a termination payment for a maximum amount of up to $150 million. Liberty must first proceed against PG&E NEG’s guarantee, and can demand payment under PG&E GTN’s guarantee only if (1) PG&E NEG is in bankruptcy or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PG&E ET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

DTE Georgetown — By letter dated October 14, 2002, DTE provided notice to PG&E ET that the downgrade of PG&E GTN constituted a material adverse change under the tolling agreement between PG&E ET and DTE and that PG&E ET was required to post replacement security within ten days. By letter dated October 23, 2002, PG&E ET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET was not required to post replacement security. If PG&E ET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment.

issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002 that it was terminating the tolling agreement effective November 29, 2002. Calpine has indicated that this termination was improper and constituted a default under the agreement, but has not taken any further action.

Southaven and Caledonia Tolling Agreements — PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing an investment-grade guarantee from PG&E NEG as defined in the agreement. The amount of the guarantee now does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the tolling agreement had taken place as PG&E NEG was no longer investment-grade as defined in the tolling agreement and because PG&E ET had failed to provide within 30 days from the downgrade substitute credit support that met the requirements of the agreement. Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the agreement, concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

In addition, PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the agreement. The amount of the guarantee does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the tolling agreement had taken place with respect to this obligation as PG&E NEG was no longer investment-grade as defined in the tolling agreement and as PG&E ET had failed to provide within thirty days from the downgrade substitute credit support that met the requirement of the agreement. Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia’s performance under the agreement, concerning the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

On February 7, 2003, Southaven and Caledonia filed an emergency petition to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court for Montgomery County, Maryland. On March 3, 2003, the court issued an order ruling that P&GE ET must continue to perform under the agreements. PG&E ET appealed this decision to an intermediate Maryland Appellate Court. However, on April 8, the highest Appellate Court in Maryland issued on its own motion an order taking jurisdiction of the appeal.

PG&E ET is not able to predict whether the counter parties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether or the extent to which, these proceedings will have a material adverse effect on PG&E NEG’s financial condition or results of operation.

Under each tolling agreement determination of the termination payment is based on a formula that takes into account a number of factors including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as six months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG does not currently expect to be able to pay any termination payments that may become due.

PG&E NEG has provided guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. PG&E NEG does not believe that it has significant exposure under these guarantees. The most significant of these guarantees relate to performance under certain construction contracts. In the event PG&E NEG is unable to provide any additional or replacement security which may be required as a result of rating downgrades, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages. These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG’s power plants and pipelines. These guarantees are described below.

PG&E NEG had issued guarantees to construction financing lenders for the performance of the contractors building the Harquahala and Covert power projects for up to $555 million. See additional discussion in “Legal Matters” in the Notes to Consolidated Financial Statements.

PG&E NEG has issued $100 million of guarantees to the constructor of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements. See additional discussion in “Legal Matters” in the Notes to Consolidated Financial Statements.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a subsidiary, Attala Energy, has entered into with Attala Generating.

The balance of the guarantees are for commitments undertaken by PG&E NEG or its subsidiaries in the ordinary course of business for services such as facility and equipment leases, ash disposal rights, and surety bonds.

PG&E NEG has the following credit facilities outstanding at March 31, 2003 (in millions):


(a)	PG&E NEG is currently in default on both its Tranche A and Tranche B credit facility.

The cash from operations for the three months ended March 31, 2003 and 2002 will not be indicative of the future cash flow from operations due to the changes in the operations of PG&E NEG discussed above. To the extent that the commitments of PG&E NEG and its subsidiaries can be restructured, future cash from operations will be principally generated by the PG&E NEG pipeline business as well as dividends from PG&E NEG independent power producer project companies which are principally accounted for under the equity method of accounting. If the commitments are not restructured, PG&E NEG will not generate sufficient funds to meet its outstanding cash requirements and may file or be compelled to seek protection under or forced involuntarily into proceedings under the Bankruptcy Code.

In addition to the impacts of PG&E NEG’s downgrades, PG&E NEG’s and its subsidiaries’ ability to service these obligations is impacted by constraints on the ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E National Energy Group, LLC, a subsidiary of PG&E Corporation, owns

97 percent of the stock of PG&E NEG. GTN Holdings LLC owns 100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC owns 100 percent of the stock of PG&E ET. The organizational documents of PG&E NEG and these limited liability companies require unanimous approval of their respective boards of directors, including at least one independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency or similar proceedings or actions. The limited liability companies may not declare or pay dividends unless the respective boards of directors unanimously approve such action and PG&E NEG meets specified financial requirements.

PG&E NEG’s subsidiaries must now independently determine, in light of each company’s financial situation, whether any proposed dividend, distribution or intercompany loan is permitted and is in such subsidiary’s interest. Therefore, consolidated statements of cash flow and consolidated balance sheets quantifying PG&E NEG’s cash and cash equivalents do not reflect the cash actually available to PG&E NEG or any particular subsidiary to meet its obligations.

At March 31, 2003, PG&E NEG and its subsidiaries had the following unrestricted cash and short-term investment balances (in millions):

Results from PG&E NEG’s consolidated cash flows from operating activities for the three months ended March 31, 2003 and 2002 are as follows on a summarized basis (in millions):

During the three months ended March 31, 2003, PG&E NEG did not provide any net cash from operating activities versus cash generated from operating activities of $43 million for the three months ended March 31, 2002. Net cash from operating activities before changes in operating assets and liabilities and price risk management assets and liabilities was $146 million less for the three months ended March 31, 2003 versus 2002, principally as a result of operating losses. Change in price risk management assets and liabilities resulted in a $46 million use of cash for the three months ended March 31, 2003 versus $21 million provided for the same period in 2002 primarily due to realized losses from pricing changes and trade terminations. The change

in inventories, prepaid expenses, deposits, and other liabilities created cash flow of $157 million for the three months ended March 31, 2003 versus $92 million used for the same period in 2002 primarily due to reduced inventory levels and prepaid expenses. Adding to these cash outflows were $65 million of increased restricted cash requirements for three months ended March 31, 2003.

The cash outflows from investing activities for the three months ended March 31, 2003 and 2002 will not be indicative of the future cash outflow from investing activities due to the changes in the operations of PG&E NEG (discussed above). Future cash outflows from investing operations will be principally related to maintenance of capital expenditures in the pipeline business.

Results from PG&E NEG’s consolidated cash flows from investing activities for the three months ended March 31, 2003 and 2002 are as follows (in millions):

Total capital expenditures detailed by business segment and expenditure amount associated with construction work in progress for the three months ended March 31, 2003 and 2002 are as follows (in millions):

During the three months ended March 31, 2003, PG&E NEG used net cash before proceeds of sale of assets of $85 million in investing activities compared to $357 million for the same period in 2002, or a decrease of $272 million. The decrease in cash used in investing activities from period to period was primarily due to reduced construction activities. In addition, PG&E NEG received proceeds on the sale of Mountain View during the first quarter of 2003 with no comparable like event occurring in the first quarter of 2002. Capital expenditures related to construction work in progress for the three months ended March 31, 2003 were $90 million versus $315 million in 2002 and were financed by non-recourse debt. In connection with the lenders’ waivers of PG&E NEG’s failure to make required equity contributions under its guarantees, these construction projects are required to be transferred to lenders during 2003.

Included in investing activities for the three months ended March 31, 2003 and 2002, are cash flows of $16 million and $21 million, respectively, related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities.

Results from PG&E NEG’s consolidated cash flows from financing activities for the three months ended March 31, 2003 and 2002 are as follows (in millions):

During the three months ended March 31, 2003, PG&E NEG provided net cash flows from financing activities of $133 million compared to $239 million for the same period in 2002. PG&E NEG’s cash inflows from financing activities were primarily attributable to increases in long-term debt issued relating to increased borrowings under PG&E NEG’s continuing construction facilities.

The following table shows for the three months ended March 31, 2003 and 2002, certain items from the accompanying Consolidated Statements of Operations detailed by reportable segments of PG&E NEG. (In the “Total” column, the table shows the combined results of operations for those items). The information for PG&E NEG (the “Total” column) includes the appropriate intercompany eliminations.

Results of operations by segment are discussed following this table (in millions):

PG&E NEG has experienced significant impacts to its results of operations from various acquisitions, disposals, and more recently from its efforts to raise cash and reduce indebtedness through sale, transfer or abandonment of assets.

Overall Results: PG&E NEG’s net loss was $369 million for the three months ended March 31, 2003, a decrease of $406 million from the three months ended March 31, 2002.

The three months ended March 31, 2003 included a net loss recognized on disposals of assets held for sale of $7 million. This amount related to the gain on sale of Mountain View of $19 million, offset by additional losses on USGenNE of $23 million, and additional losses on the sale of ET Canada of $3 million. No gains or losses on disposal of assets held for sale were reflected in the comparative period in 2002. In addition, losses from discontinued operations were $100 million for the three months ended March 31, 2003 or a $108 million decrease from the comparative period in 2002. These losses from discontinued operations were primarily due to lower gross margin results from USGenNE. Gross margin is defined as the difference between revenues and cost of commodity.

PG&E NEG’s pre-tax operating loss of $293 million for the three months ended March 31, 2003 was $327 million lower income than the comparative period in 2002. The reduced pre-tax operating levels period over period were principally due to $200 million of impairment and write-offs charged to income in the first quarter 2003 resulting primarily from the consolidation and impairment of Attala Generating Company, LLC and the Shaw settlement as further discussed in Note 6 of the Notes to the Consolidated Financial Statements. In addition, gross margins were $7 million less in the first quarter 2003 compared to the same period in 2002 primarily due to the winding down of PG&E NEG’s energy trading operations. Increased operation and maintenance costs of $20 million and increased interest expense of $89 million in the first quarter 2003 compared to the same period in 2002 adversely impacted pre-tax operating income and were primarily due to new merchant plants in operation. Administrative and general expense were $16 million higher in the first quarter 2003 compared to 2002 primarily due to costs associated with PG&E NEG’s debt restructuring efforts. Tax benefits recorded in the first quarter 2003 of $39 million reflect adjustments to the tax valuation allowances. No such tax valuation allowance was recorded in the comparative period in 2002.

The following highlights the principal changes in operating revenues and operating expenses.

Operating Revenues: PG&E NEG’s operating revenues were $565 billion in the three months ended March 31, 2003, a increase of $49 million from the three months ended March 31, 2002. These slight increases occurred primarily in the Integrated Energy and Marketing Activities segment and are primarily a result of the activities associated with the winding down of PG&E NEG’s energy trading operations. Interstate Pipeline Operations operating revenues increased $5 million primarily due to the addition of the North Baja pipeline operations compared to the same period last year.

Operating Expenses: PG&E NEG’s operating expenses were $744 million in the three month period ended March 31, 2003, a increase of $284 million from the same period in the prior year. These increases occurred primarily as a result of $200 million impairment and write-off charges in the first quarter 2003. The cost of commodity sales and fuel increased $49 million in line with increases in operating revenues and were primarily attributable to the activities associated with the winding down of PG&E NEG’s energy trading operations. Operations, maintenance and management costs increased $20 million in the first quarter of 2003 as compared to the same period last year principally due to additional merchant generation facilities in operations. Administrative and general expenses were $16 million higher in the first quarter 2003 compared to 2002 primarily due to costs associated with PG&E NEG’s debt restructuring efforts.

PG&E NEG is exposed to various risks associated with its operations, the marketplace, contractual obligations, financing arrangements and other aspects of its business. PG&E NEG actively manages these risks through risk management programs. These programs are designed to support business objectives, minimize costs, discourage unauthorized risk, and reduce the volatility of earnings and manage cash flows. At PG&E NEG risk management activities often include the use of energy and financial derivative instruments and other instruments and agreements. These derivatives include forward contracts, futures, swaps, options, and other contracts.

PG&E NEG uses derivatives for both non-trading (i.e., risk mitigation) and trading (i.e., speculative) purposes. PG&E NEG may use energy and financial derivatives and other instruments and agreements to mitigate the risks associated with an asset (e.g., the natural position embedded in asset ownership and regulatory arrangements), liability, committed transaction, or probable forecasted transaction. Additionally, PG&E NEG may engage in trading activities for purposes of generating profit, gathering market intelligence, creating liquidity, and maintaining a market presence. These instruments are used in accordance with approved risk management policies adopted by a senior officer-level risk oversight committee. Derivative activity is permitted only after the risk oversight committee approves appropriate risk limits for such activity. The organizational unit proposing the activity must successfully demonstrate that there is a business need for such activity and that the market risks will be adequately measured, monitored, and controlled.

The activities affecting the estimated fair value of trading activities and the non-trading activities balance, included in net price risk management assets and liabilities, are presented below (in millions).

PG&E NEG estimates the gross mark-to-market value of its non-trading and trading contracts at March 31, 2003, using the mid-point of quoted bid and ask prices, where available. When market data is not available, PG&E NEG uses a model that estimates forward power prices using the mid-point of the marginal cost curve (the lowest variable cost of generation available in a region) and the forecast curve (the price at which a generation unit will recover its capital costs and a return of investment). Interpolation methods are used for intermediate periods when broker quotes are unavailable. The gross mark-to-market valuation is then adjusted for the time value of money, creditworthiness of contractual counterparties, market liquidity in future periods, and other adjustments necessary to determine fair value. Most of PG&E NEG’s risk management models are reviewed by or purchased from third-party experts in specific derivative applications.

The following table shows the fair value of PG&E NEG’s trading contracts grouped by maturity at March 31, 2003 (in millions).


(1)	Excludes all non-trading contracts, including non-trading contracts that receive mark-to-market accounting treatment.

(2)	Actively quoted markets are exchanged traded quotes.

(3)	In many cases, these prices are an input into option models that calculate a gross mark-to-market value from which fair value is derived.

The amounts disclosed above are not indicative of likely future cash flows. The future value of trading contracts may be impacted by changes in underlying valuations, new transactions, market liquidity, and PG&E NEG risk management portfolio needs and strategies.

Market risk is the risk that changes in market conditions will adversely affect earnings or cash flow. PG&E NEG categorizes its market risks as price risk, interest rate risk, foreign currency risk, and credit risk. These market risks may impact PG&E NEG and its subsidiaries’ assets and trading portfolios.

Price risk is the risk that changes in commodity market prices will adversely affect earnings and cash flows.

PG&E NEG is exposed to price risk from its portfolio of proprietary trading contracts and its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, and various merchant plants currently in development and construction.

As described above, PG&E NEG is in the process of reducing and unwinding its trading positions. Additionally, asset hedge positions associated with the merchant plants will either remain with the assets or be terminated. PG&E NEG has significantly reduced its energy trading operations in an ongoing effort to raise cash and reduce debt. PG&E NEG’s objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer, or abandonment process. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations.

PG&E NEG measures price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the probability of future potential losses. Price risk is quantified using what is referred to as the variance-covariance technique of measuring value-at-risk, which provides a consistent measure of risk across diverse energy markets and products. This methodology requires the selection of a number of important assumptions, including a confidence level for losses, price volatility, market liquidity, and a specified holding period. This technique uses historical price movements data and specific, defined mathematical parameters to estimate the characteristics of and the relationships between components of assets and liabilities held for price risk management activities. PG&E NEG therefore uses the historical data for calculating the expected price volatility of its portfolio’s contractual positions to project the likelihood that the prices of those positions will move together.

The value-at-risk model includes all of PG&E NEG’s commodity derivatives and other financial instruments over the entire length of the terms of the transactions in the trading and non-trading portfolios. PG&E NEG’s value-at-risk calculation is a dollar amount reflecting the maximum potential one-day loss in the fair value of their portfolios due to adverse market movements over a defined time horizon within a specified confidence level. This calculation is based on a 95 percent confidence level, which means that there is a 5 percent probability that PG&E NEG’s portfolios will incur a loss in value in one day at least as large as the reported value-at-risk. For example, if the value-at-risk is calculated at $5 million, there is a 95 percent probability 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. There would also be a 5 percent probability that a one-day price movement would be greater that $5 million.

The following table illustrates the potential one-day unfavorable impact for price risk as measured by the value-at-risk model, based on a one-day holding period. A comparison of daily value’s-at-risk as of March 31, 2003 and as of December 31, 2002, is included in order to provide context around the one-day amounts (in millions).


(1)	Includes derivative power and fuels contracts that do not qualify as normal purchases and normal sales exception and do not qualify to be accounted for as cash flow hedges under Statement of Financial Accounting Standards (SFAS) No. 133.

(2)	Includes only the risk related to the derivative instruments that serve as hedges and does not include the related underlying hedged item. Any gain or loss on these derivative commodity instruments would be substantially offset by a corresponding gain or loss on the hedged commodity positions, which are not included.

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.

PG&E NEG’s value-at-risk for trading and non-trading activities has increased at March 31, 2003, as compared to levels at March 31, 2002, due to strong prices and increased market volatility across all commodities. As PG&E NEG continues to wind down its trading positions, additional increases in prices or volatility could cause value-at-risk levels to increase. See the discussion above in the MD&A’s Liquidity and Financial Resources section for further information regarding PG&E NEG’s current financial situation.

Interest rate risk is the risk that changes in interest rates could adversely affect earnings or cash flows. Specific interest rate risks for PG&E NEG include the risk of increasing interest rates on working capital facilities and variable rate debt.

PG&E NEG may use 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 risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. At March 31, 2003, if interest rates change by 1 percent for all variable rate debt at PG&E NEG, the change would affect net income by approximately $15 million for PG&E NEG based on variable rate debt and hedging derivatives and other interest rate-sensitive instruments outstanding.

Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies in relation to the U.S. dollar.

PG&E NEG is exposed to such risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements. PG&E NEG may use forwards, swaps, and options to hedge foreign currency exposure.

PG&E NEG uses sensitivity analysis to measure its exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at March 31, 2003, a 10 percent devaluation of the Canadian dollar would be immaterial to PG&E NEG’s Consolidated Financial Statements.

Credit risk is the risk of loss that PG&E NEG would incur if counterparties failed to perform their contractual obligations (these obligations are reflected as: Accounts receivable — trade, net; notes receivable included in Other noncurrent assets — other; PRM assets; and Assets held for sale on the Consolidated Balance Sheet). PG&E NEG conducts business primarily with customers or vendors, referred to as counterparties, in the energy industry. These counterparties include other investor-owned utilities, municipal utilities, energy trading companies, financial institutions, and oil and gas production companies located in the United States and Canada. This concentration of counterparties may impact PG&E NEG’s overall exposure to credit risk because their counterparties may be similarly affected by economic or regulatory changes or other changes in conditions.

PG&E NEG manages its credit risk in accordance with PG&E Corporation Risk Management Policy. This establishes processes for assigning credit limits to counterparties before entering into agreements with significant exposure to PG&E NEG. These processes 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.

During the three months ended March 31, 2003, PG&E NEG’s credit risk has decreased primarily due to contract terminations with counterparties. PG&E NEG recognized no losses due to contract defaults or bankruptcies of counterparties during the three months ended March 31, 2003.

The schedule below summarizes PG&E NEG’s credit risk exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis) at March 31, 2003, and December 31, 2002 (in millions):


(1)	Gross credit exposure equals mark-to-market value notes receivable, and net (payables) receivables where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value, liquidity, model or credit reserves.

(2)	Net credit exposure is the gross credit exposure minus credit collateral (cash deposits and letters of credit).

PG&E NEG’s regional concentrations of credit exposure are to counterparties that conduct business primarily throughout North America.

The preparation of consolidated financial statements in accordance with accounting principles generally accepted in the United States involves the use of estimates and assumptions that affect the recorded amounts of assets and liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Certain of these estimates and assumptions are considered to be Critical Accounting Policies, due to their complexity, subjectivity, and uncertainty, along with their relevance to the financial performance of PG&E NEG. Actual results may differ substantially from these estimates. These policies and their key characteristics are outlined below.

Derivative and Energy Trading Activities — In 2001, PG&E NEG 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 derivative instruments to be recognized in the financial statements at their fair value. Prior to its rescission, PG&E NEG accounted for its energy trading activities in accordance with EITF No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (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.

Effective for the third quarter ended September 30, 2002, PG&E NEG adopted the net method of recognizing realized gains and losses on energy trading contracts. Under the net method, revenues and expenses are netted and trading gains (or losses) are reflected in revenues on the income statement, as opposed to reporting revenues and expenses under the previously used gross method.

PG&E NEG also has derivative commodity contracts for the physical delivery of purchase and sale quantities such as natural gas and electricity transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and are not reflected on the balance sheet at fair value. See further discussion in Note 6 of the Notes to the Consolidated Financial Statements.

Regulatory Assets and Liabilities — PG&E NEG applies SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation,” to its regulated operations. Under SFAS No. 71, regulatory assets represent capitalized costs that would otherwise be charged to expense. These costs are later recovered through regulated rates. Regulatory liabilities are rate actions of a regulator that will later be credited to customers through the rate making process. Regulatory assets and liabilities are capitalized when it is probable that these items will be recovered or reflected in future rates. If it is determined that these items are no longer subject to recoverability under SFAS No. 71, then they will be written-off at that time.

on Derivative Instruments and Hedging Activities” (SFAS No. 149). SFAS No. 149 amends and clarifies the accounting and reporting for derivative instruments, including certain derivatives embedded in other contracts, and for hedging activities under SFAS No. 133. The amendments in SFAS No. 149 require that contracts with comparable characteristics be accounted for similarly. The Statement clarifies under what circumstances a contract with an initial net investment meets the characteristics of a derivative according to SFAS No. 133 and when a derivative contains a financing component that warrants special reporting in the statement of cash flows. In addition, the Statement amends the definition of an underlying to conform it to language used in FASB Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”, and amends certain other existing pronouncements. The provisions of the Statement that relate to SFAS No. 133 Implementation Issues that have been effective for periods that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates.

FIN 46 requires disclosures of variable interest entities that the company is not required to consolidate but in which it has a significant variable interest.

PG&E NEG accounts for income taxes under the liability method. Deferred tax assets and liabilities are determined based on the differences between financial statement carrying amounts and the tax basis of assets and liabilities, using currently enacted tax rates. PG&E NEG is included in the consolidated tax return of PG&E Corporation. PG&E NEG computes its provision for income taxes on a separate company basis as if it filed its own consolidated or combined tax return separate from PG&E Corporation.

Certain states require that each entity doing business in that state file a separate tax return (the “Separate State Taxes”). Canadian subsidiaries are subject to Canadian Federal and Provincial Income Taxes based on their net income (the “Canadian Taxes”). PG&E NEG separately accounts for the tax consequences of Separate State Taxes and Canadian Taxes.

For certain of the years before 2001, PG&E Corporation made payments to PG&E NEG commensurate with the tax savings achieved through the incorporation of PG&E NEG’s losses and tax credits in PG&E Corporation’s consolidated federal tax return for those years. In tax year 2001, PG&E NEG paid to PG&E Corporation the amount of its federal tax liability. Certain creditors of PG&E NEG have asserted that the aforementioned payments gave rise to an implied tax sharing agreement between PG&E Corporation and PG&E NEG. PG&E Corporation disputes that assertion. On November 12, 2002, PG&E Corporation notified PG&E NEG that to the extent that such an implied tax sharing agreement existed and was not terminated previously, it was terminated effective immediately. On December 24, 2002, PG&E NEG sent a letter to PG&E Corporation reserving all rights against PG&E Corporation with respect to such tax sharing agreement, if such agreement does in fact exist.

Under the PG&E Corporation Credit Agreement, PG&E Corporation agreed among other things not to permit PG&E NEG or any of its subsidiaries to (1) sell or abandon any of their respective assets except in compliance with certain conditions or (2) restructure any of their respective obligations except in compliance with certain conditions. These prohibitions do not apply to a “Qualified Asset Sale,” a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring,” all as defined in the PG&E Corporation Credit Agreement. In general, these definitions permit transactions in which PG&E Corporation (1) is released from existing liabilities related to the assets that are the subject of the transaction, (2) incurs no new liabilities as a result of the transaction, and (3) receives payment at closing for any new liability incurred, including any tax liability that would be payable as a result of the transaction. The PG&E Credit Agreement also restricts (with limited exceptions) PG&E Corporation’s investment in PG&E NEG to an amount that is no more than 75 percent of the net cash tax savings received by PG&E Corporation after October 1, 2002, as a result of a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring” (as defined in the PG&E Credit Agreement).

In 2002, PG&E NEG recorded valuation allowances due to the continued uncertainty in realizing federal and state deferred tax assets. During the first quarter of 2003, valuation allowances of $76 million were recorded in continuing operations. Additional valuation allowances of $45 million were recorded in discontinued operations, $3 million recorded in cumulative effect of a change in an accounting principle, and $53 million recorded in accumulated other comprehensive loss. These valuation allowances were established for the full amount of the federal and state deferred taxes.

The Internal Revenue Service (IRS) has completed its audit of PG&E Corporation’s 1997 and 1998 consolidated U.S. federal income tax returns and has assessed additional federal income taxes of $53 million (including interest) related to PG&E NEG. PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and is currently discussing those adjustments with the IRS’s Appeals Office.

The IRS is also auditing PG&E Corporation’s 1999 and 2000 consolidated U.S. federal income tax returns, but has not issued its final report. However, the IRS has proposed adjustments totaling $68 million (including interest) with respect to PG&E NEG. All of PG&E Corporation’s federal income tax returns before 1997 have been closed, including those portions attributable to PG&E NEG. In addition, the State of California’s Franchise Tax Board and certain other state tax authorities are currently auditing various state tax returns.

PG&E NEG is subject to laws and regulations established both to maintain and improve the quality of the environment. Where PG&E NEG properties contain hazardous substances, these laws and regulations require PG&E NEG to remove those substances or remedy effects on the environment. Also, in the normal course of business, PG&E NEG is named as a party in a number of claims and lawsuits. See Note 4 of the

PG&E NEG’s primary market risk results from changes in energy commodity prices and interest rates. PG&E NEG engages in price risk management activities for both non-trading and trading purposes. Additionally, PG&E NEG may engage in trading and non-trading activities using forward contracts, futures, options, and swaps and other contracts to hedge the impact of market fluctuations on energy commodity prices, interest rates, and foreign currencies. (See Risk Management Activities, included in Management’s Discussion and Analysis above.)

Based on an evaluation of PG&E NEG’s disclosure controls and procedures conducted on April 21, 2003, PG&E NEG’s principal executive and principal financial officers have concluded that such controls and procedures effectively ensure that information required to be disclosed by PG&E NEG in reports the company files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time periods specified in the Securities and Exchange Commission (SEC) rules and forms.

There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

California Energy Trading Litigation — For information regarding these matters, see PG&E NEG’s Annual Report on Form 10-K for the year ended December 31, 2002, as amended.

Brayton Point — For information regarding this matter, see PG&E NEG’s Annual Report on Form 10-K for the year ended December 31, 2002, as amended.

Natural Gas Royalties Litigation — For information regarding this matter, please see Note 4 “Legal Matters” of the Notes to the Consolidated Financial Statements.

North Baja Pipeline Litigation — For information regarding this matter, see PG&E NEG’s Annual Report on Form 10-K for the year ended December 31, 2002, as amended.

Shaw Litigation — For information regarding this matter, please see Note 4 “Legal Matters” of the Notes to the Consolidated Financial Statements.

Mitsubishi Litigation — For information regarding this matter, please see Note 4 “Legal Matters” of the Notes to the Consolidated Financial Statements.

Southaven and Caledonia Tolling Agreements. For information regarding this matter, please see Note 4 “Tolling Agreements” of the Notes to the Consolidated Financial Statements.

PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition other PG&E NEG subsidiaries are in defaults under various debt agreements totaling $2.7 billion, but this debt is non-recourse to PG&E NEG. For more information, please see Note 3 of the Notes to the Consolidated Financial Statements.

(b) The following Current Reports on Form 8-K were filed during the first quarter of 2003 and through the date hereof:

PG&E NEG filed a current report on Form 8-K on January 16, 2003 disclosing the funding of certain projects and related agreements.

PG&E NEG filed a Current Report on Form 8-K on March 21, 2003, disclosing recent litigation and the disposition of certain assets.

PG&E NEG filed a Current Report on Form 8-K on April 2, 2003, disclosing arrangement made under certain agreements and the change in ownership.

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the city of Bethesda, state of Maryland.


	By:	/s/ THOMAS E. LEGRO



	Thomas E. Legro
	Vice President, Controller and
	Chief Accounting Officer

1. I have reviewed this quarterly report on Form 10-Q of PG&E National Energy Group, Inc.;

2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report;

3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report;

4. The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:


	• designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	• evaluated the effectiveness of the registrant’s disclosure controls and procedures within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	• presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent function):


	• all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	• any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and

6. The registrant’s other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

1. I have reviewed this quarterly report on Form 10-Q of PG&E National Energy Group, Inc.;


	• designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

	• evaluated the effectiveness of the registrant’s disclosure controls and procedures within 90 days prior to the filing date of this quarterly report (the “Evaluation Date”); and

	• presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;


	• all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant’s ability to record, process, summarize and report financial data and have identified for the registrant’s auditors any material weaknesses in internal controls; and

	• any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal controls; and


	/s/ THOMAS E. LEGRO

	Thomas E. Legro
	Vice President, Controller and
	Chief Accounting Officer


(Mark one)
þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended March 31, 2003

OR

o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to


		Page

PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements		2
	Consolidated Statements of Operations		2
	Consolidated Balance Sheets		3
	Consolidated Statements of Cash Flows		5
	Notes to Consolidated Financial Statements		6
	Note 1: General		6
	Note 2: Relationship with PG&E Corporation		12
	Note 3: Liquidity and Financing Matters		13
	Note 4: Commitments and Contingencies		17
	Note 5: Discontinued Operations and Assets Held for Sale		28
	Note 6: Impairments, Write-offs and Other Charges		31
	Note 7: Price Risk Management		32
	Note 8: Segment Information		36
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		37
	Overview		37
	Market Conditions and Business Environment		41
	Commitments and Contingencies		42
	Guarantees		42
	Cash Flows		46
	Results of Operations		49
	Risk Management Activities		51
	Critical Accounting Policies		56
	Accounting Pronouncements Issued but Not Yet Adopted		56
	Tax Matters		57
	Environmental and Legal Matters		58
Item 3.	Quantitative and Qualitative Disclosures about Market Risks		59
Item 4.	Controls and Procedures		59
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		59
Item 3.	Defaults Upon Senior Securities		59
Item 6.	Exhibits and Reports on Form 8-K		60
Signatures and Certifications			61



			(Unaudited)
			Three Months
			Ended March 31,

			2003			2002


			(in millions)
Operating Revenues
	Generation, transportation, and trading		$	540		$	498
	Equity in earnings of affiliates			25			18

		Total operating revenues		565			516

Operating Expenses
	Cost of commodity sales and fuel			389			340
	Operations, maintenance, and management			98			78
	Administrative and general			23			7
	Depreciation and amortization			26			31
	Impairments, write-offs and other charges			200			—
	Other operating expenses			8			4

Total operating expense				744			460

Operating Income (Loss)				(179	)		56
	Interest income			2			6
	Interest expense			(122	)		(33	)
	Other income, net			6			5

Income (Loss) Before Income Taxes				(293	)		34
	Income tax expense (benefit)			(39	)		5

Income (Loss) From Continuing Operations				(254	)		29

Discontinued Operations
	Earnings (loss) from operations of USGenNE, Mountain View and ET Canada, net of applicable income tax expense of $5 million for three months ended March 31, 2002			(100	)		8

	Net loss on disposal of USGenNE, Mountain View and ET Canada, net of zero applicable income tax expense			(7	)		—
Net Income (Loss) Before Cumulative Effect Of A Change In Accounting Principle				(361	)		37
Cumulative Effect Of A Change In Accounting Principle, net of zero applicable income tax benefits				(8	)		—

Net Income (Loss)			$	(369	)	$	37



				Balance at

				(Unaudited)
				March 31,			December 31,
				2003			2002


				(in millions)
ASSETS
Current Assets
	Cash and cash equivalents			$	513		$	363
	Restricted cash				246			181
	Accounts receivable:
		Trade (net of allowance for uncollectibles of $46 million and $55 million, respectively)			778			819
		Related parties			20			44
	Other receivables				18			28
	Inventory				35			72
	Credit collateral deposits				249			245
	Price risk management				717			498
	Prepaid expenses and other				89			117
	Assets held for sale				266			707

			Total current assets		2,931			3,074

Property, Plant and Equipment
	Electric generating facilities				940			578
	Gas transmission assets				1,778			1,760
	Land				57			56
	Other				169			159
	Construction work in progress				823			1,133

		Total property, plant and equipment			3,767			3,686
	Accumulated depreciation				(726	)		(723	)

			Net property, plant and equipment		3,041			2,963

Other Noncurrent Assets
	Investments in unconsolidated affiliates				414			403
	Intangible assets, net of accumulated amortization of $22 million and $22 million, respectively				35			37
	Deferred financing costs, net of accumulated amortization of $103 million and $70 million, respectively				69			102
	Price risk management				264			398
	Other				49			52
	Assets held for sale				810			916

			Total other noncurrent assets		1,641			1,908

			TOTAL ASSETS	$	7,613		$	7,945



				Balance at

				(Unaudited)
				March 31,			December 31,
				2003			2002


				(in millions)
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY (DEFICIT)
Current Liabilities
	Debt in default			$	4,373		$	4,230
	Long-term debt, classified as current				10			17
	Accounts payable:
		Trade			857			893
		Related parties			49			47
	Accrued expenses				361			285
	Price risk management				642			506
	Other				22			26
	Liabilities held for sale				353			699

			Total current liabilities		6,667			6,703

Noncurrent Liabilities
	Long-term debt				865			630
	Deferred income taxes				—			—
	Price risk management				259			305
	Long-term advances from PG&E Corporation				327			327
	Other noncurrent liabilities and deferred credit				107			150
	Liabilities held for sale				758			793

			Total noncurrent liabilities		2,316			2,205

Minority Interest					21			19
Commitments and Contingencies (See Note 4)					—			—
Preferred Stock of Subsidiary					58			58
Common Stockholders’ Equity (Deficit)
	Common stock, $1.00 par value — 1,000 shares issued and outstanding							—
	Paid-in capital				3,086			3,086
	Accumulated deficit				(4,402	)		(4,033	)
	Accumulated other comprehensive loss				(133	)		(93	)

			Total common stockholders’ equity (deficit)		(1,449	)		(1,040	)

			TOTAL LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY (DEFICIT)	$	7,613		$	7,945


Delaware (State or Other Jurisdiction of Incorporation or Organization)		7600 Wisconsin Avenue (Mailing address: 7500 Old Georgetown Road) Bethesda, Maryland 20814 (301) 280-6800		94-3316236 (I.R.S. Employer Identification Number)


	*Adoption of New Accounting Policies and Summary of Significant Accounting Policies*


	Prior Method of
	Presentation		As Presented
	(Gross Method)		(Net Method)

	Three Months Ended		Three Months Ended
	March 31, 2002		March 31, 2002

Generation, transportation and trading	$	2,114	$	498
Cost of commodity, sales and fuel		1,956		340

Net Subtotal	$	158	$	158



						Receivable (Payable)
						Balance
		Three Months				Outstanding at
		Ended March 31,				March 31,

		2003		2002		2003			2002

Sales to the Utility from:
	PG&E ET — energy commodities	$	11	$	20	$	11	^(C)	$	27	^(A)
	PG&E GTN — transportation of gas	$	15	$	12	$	8	^(B)	$	7
	PG&E NEG — shared costs	$	1	$	—	$	1		$	1
Purchases from the Utility by:
	PG&E ET — energy commodities	$	3	$	2	$	(3	)	$	(1	)



						Outstanding Balance At

						March 31,		December 31,
Description		Maturity		Interest Rates		2003		2002

Debt in Default
PG&E NEG, Inc. Senior Unsecured Notes			2011		10.375%	$	1,000	$	1,000
PG&E NEG, Inc. Credit Facility-Tranche B (364-day)			11/14/02		Prime plus credit spread		431		431
PG&E NEG, Inc. Credit Facility-Tranche A (2-year facility with a $258 million maximum commitment)			8/23/03		Prime plus credit spread		73		42
Turbine and Equipment Facility			12/31/03		Prime plus credit spread		205		205
GenHoldings Construction Facility Tranche A			12/5/03		LIBOR plus credit spread		194		118
GenHoldings Construction Facility Tranche B			12/5/03		LIBOR plus credit spread		1,068		1,068
GenHoldings Swap Termination							50		50
Lake Road Construction Facility Tranche A			12/11/02		Prime plus credit spread		227		227
Lake Road Construction Facility Tranche B			12/11/02		Prime plus credit spread		219		219
Lake Road Construction Facility Tranche C					Prime plus credit spread		—		—
Lake Road Working Capital Facility			12/9/03		Prime plus credit spread		27		23
Lake Road Swap Termination			12/11/02				61		61
La Paloma Construction Facility Tranche A			12/11/02		Prime plus credit spread		374		367
La Paloma Construction Facility Tranche B			12/11/02		Prime plus credit spread		296		291
La Paloma Construction Facility Tranche C			12/11/02		Prime plus credit spread		21		20
La Paloma Working Capital Facility			12/9/03				46		29
La Paloma Swap Termination			12/11/02				81		79

	Subtotal					$	4,373	$	4,230

Long-term debt
PG&E GTN Senior Unsecured Notes			2005		7.10%	$	250	$	250
PG&E GTN Senior Unsecured Debentures			2025		7.80%		150		150
PG&E GTN Senior Unsecured Notes			2012		6.62%		100		100
PG&E GTN Medium-Term Note			2003		6.96%		6		6
PG&E GTN Credit Facility			5/2/05		LIBOR plus credit spread		40		58
USGenNE Credit Facility			9/1/03		LIBOR plus credit spread		75		75
Plains End Construction Facility			9/6/06		LIBOR plus credit spread		65		56
Other debt related to Attala			Various		Principally LIBOR plus		237		—
					credit spread
Mortgage loan payable			2010		CP rate + 6.07%		7		7
Other			Various		Various		20		20

	Subtotal					$	950	$	722

Total Debt in default and Long-term debt						$	5,323	$	4,952


PG&E NEG Senior Unsecured Notes	$	91
PG&E NEG Inc. Credit Facility		17
Turbine and Equipment Facility		7
Lake Road Facilities		16
La Paloma Facilities		4
PG&E GTN Facilities		11

Total	$	146


					Letter of Credit
			Letter of Credit		Outstanding
Borrower	Maturity		Capacity		March 31, 2003

PG&E NEG		8/03	$	185	$	185
USGenNE		8/03	$	25	$	13
PG&E Gen		12/04	$	7	$	7
PG&E ET		9/03	$	19	$	19
PG&E ET		11/03	$	35	$	33


Note 5:	Discontinued Operations and Assets Held for Sale



	Three Months
	Ended
	March 31,

	2003			2002

Trading activities:
Unrealized gains (losses), net	$	8		$	(2	)
Realized gains, net		(33	)		45

Total	$	(25	)	$	43


	PRM Assets		PRM Assets		PRM Liabilities			PRM Liabilities			Net PRM Assets
	Current		Noncurrent		Current			Noncurrent			Liabilities

*Trading activities*	$	688	$	202	$	(632	)	$	(247	)	$	11
*Non-trading activities*		29		62		(10	)		(12	)		69

Total consolidated PRM Assets and Liabilities	$	717	$	264	$	(642	)	$	(259	)	$	80


	Note 1: General


	*Organization and Basis of Presentation*


	*Stock-Based Compensation*


	*Comprehensive Income*


	Gross Credit
	Exposure Before		Credit		Net Credit
	Credit Collateral⁽¹⁾		Collateral⁽²⁾		Exposure⁽²⁾

At March 31, 2003	$	497	$	96	$	401
At December 31, 2002	$	920	$	93	$	827


	Integrated Energy			Interstate
	And Marketing			Pipeline		Other and
	Activities			Operations		Eliminations(2)			Total

Three Months Ended March 31, 2003
Operating revenues	$	476		$	64	$	—		$	540
Intersegment revenues⁽¹⁾		18			—		(18	)		—
Equity in earnings of affiliates		25			—		—			25

Total operating revenues	$	519		$	64	$	(18	)	$	565

Income (loss) from continuing operations		(150	)		16		(120	)		(254	)
Net Income (loss)		(217	)		16		(168	)		(369	)
Three Months Ended March 31, 2002⁽³⁾
Operating revenues⁽⁴⁾	$	441		$	59	$	(2	)	$	498
Intersegment revenues⁽¹⁾		2			—		(2	)		—
Equity in earnings of affiliates		18			—		—			18

Total operating revenues	$	461		$	59	$	(4	)	$	516

Income (loss) from continuing operations		18			18		(7	)		29
Net Income (loss)		26			18		(7	)		37
Total assets at March 31, 2003	$	7,254		$	1,350	$	(991	)	$	7,613
Total assets at March 31, 2002	$	9,212		$	1,290	$	167		$	10,669


Item 2.	*Management’s Discussion and Analysis of Financial Condition and Results of Operations.*


Number of		Net		Primary		% of
Facilities		MW		Fuel Type		Portfolio

	8		667		Coal/Oil		45
	7		797		Natural Gas		54
	1		12		Wind		1

	16		1,476				100


	Total Bank
	Commitment		Balance

PG&E NEG Inc — Tranche A (2 year facility)(a)	$	258	$	258
PG&E NEG Inc. — Tranche B (364 day facility)(a)		431		431
PG&E ETH & Subsidiaries — Facility One		35		33
PG&E ETH & Subsidiaries — Facility Two		19		19
PG&E Gen		7		7
USGenNE		100		88
PG&E GTC and Subsidiaries		125		40

Total	$	975	$	876


PG&E NEG	$	110
PG&E ET and Subsidiaries		153
PG&E Gen and Subsidiaries		172
PG&E GTN and Subsidiaries		29
Other		49

Consolidated PG&E NEG	$	513


	Integrated
	Energy			Interstate
	And Marketing			Pipeline		Other and
	Activities			Operations		Eliminations(1)			Total

For the three months ended March 31, 2003
Total operating revenues	$	519		$	64	$	(18	)	$	565
Total operating expenses		687			27		30			744

Total operating income	$	(168	)	$	37	$	(48	)	$	(179	)

Interest income										2
Interest expense										122
Other income (expense), net										6

Loss before income tax									$	(293	)
Income taxes benefit										(39	)

Loss before discontinued operations and cumulative effect of a change in accounting principle									$	(254	)
Net loss									$	(369	)
For the three months ended March 31, 2002
Total operating revenues	$	461		$	59	$	(4	)	$	516
Total operating expenses		429			26		5			460

Total operating income	$	32		$	33	$	(9	)	$	56

Interest income										6
Interest expense										33
Other income (expense), net										5

Income before income tax									$	34
Income taxes expense										5

Income before discounted operations and cumulative effect of a change in accounting principle									$	29
Net Income									$	37


	*Three Months Ended March 31, 2003 as Compared to Three Months Ended March 31, 2002*



	Fair Value of Trading Contracts(1)

	Maturity			Maturity			Maturity			Maturity		Total
	Less than			One-Three			Four-Five			in Excess of		Fair
Source of Prices Used in Estimating Fair Value	One Year			Years			Years			Five Years		Value

Actively quoted markets⁽²⁾	$	18		$	11		$	—		$	—	$	29
Provided by other external sources		59			(82	)		(18	)		—		(41	)
Based on models and other valuation methods ⁽³⁾		(20	)		(8	)		1			50		23

Total Mark-to-Market	$	57		$	(79	)	$	(17	)	$	50	$	11


	Gross Credit
	Exposure
	Before Credit		Credit		Net Credit
	Collateral⁽¹⁾		Collateral⁽²⁾		Exposure⁽²⁾

At March 31, 2003	$	497	$	96	$	401
At December 31, 2002	$	920	$	93	$	827


Exhibit
Number		Exhibit Description

	10.1	Waiver Letter dated as of March 21, 2003, among GenHoldings I, LLC, various lenders identified as GenHoldings Lenders, the Administrative Agent, and acknowledged and agreed to by PG&E National Energy Group (incorporated by reference to PG&E Corporation’s and PG&E National Energy Group, Inc.’s Form 8-K filed April 2, 2003 (file Nos. 1-12609 and 333-66032), Exhibit 99.1)
	99.1	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
	99.2	Certification of Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


	/s/ THOMAS B. KING

	Thomas B. King
	President and Chief Executive Officer