Pg&e National Energy 10-Q 2002 Q1 Quarterly report

FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON D.C. 20549

______________________

(Mark one)

[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE     SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2002
	OR
[   ]	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE     SECURITIES EXCHANGE ACT OF 1934

                   For the transition period from ______to ______.

COMMISSION FILE NO.            333-66032            

______________________

PG&E National Energy Group, Inc.
(Exact Name of Registrant as Specified in Its Charter)

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

(Address, Including Zip Code, and Telephone Number,
Including Area Code, of Registrant’s Principal Executive Offices)

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.

     Yes       X                               No _______

PG&E National Energy Group, Inc.
Form 10-Q
For the Quarterly Period ended March 31, 2002
Table of Contents

		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 and the California Energy Crisis	9
	Note 3: Price Risk Management	10
	Note 4: Debt Financing	13
	Note 5: Commitments and Contingencies	13
	Note 6: Segment Information	19
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	20
	Overview	20
	State of the Industry	23
	Liquidity and Financial Resources	24
	Risk Management Activities	28
	Results of Operations	32
	Accounting Pronouncements Issued but Not Yet Adopted	33
	Critical Accounting Policies	34
	Environmental Matters and Legal Matters	34
Item 3.	Quantitative and Qualitative Disclosures about Market Risks	36
PART II.	OTHER INFORMATION	37
Item 1.	Legal Proceedings	37
Item 6.	Exhibits and Reports on Form 8-K	38
Signatures		39

1

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(In Millions)

			Three Months Ended
			March 31,
						As revised see
						Note 1
			2002			2001
OPERATING REVENUES
	Generation, transportation, and trading		$	2,330		$	4,180
	Equity in earnings of affiliates			18			26
		Total operating revenues		2,348			4,206
OPERATING EXPENSES
	Cost of commodity sales and fuel			2,087			3,934
	Operations, maintenance, and management			141			126
	Administrative and general			7			21
	Depreciation and amortization			48			38
	Other operating expenses			4			2
		Total operating expenses		2,287			4,121
OPERATING INCOME				61			85
	Interest income			16			25
	Interest expense, net of $46 million and $27 million capitalized			(33	)		(27	)
	Other income (expense), net			3			5
INCOME BEFORE INCOME TAXES				47			88
	Income taxes provision			10			34
NET INCOME			$	37		$	54

The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.

2

PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(In Millions)

				BALANCE AT
				March 31,			December 31,
				2002			2001
ASSETS
CURRENT ASSETS
	Cash and cash equivalents			$	691		$	725
	Restricted cash				153			141
	Accounts receivable:
		Trade, net of allowance for uncollectibles of $43 million			830			1,031
		Related parties			37			40
	Other receivables				31			54
	Inventory				117			125
	Price risk management				456			381
	Prepaid expenses and other				270			141
			Total current assets		2,585			2,638
PROPERTY, PLANT AND EQUIPMENT
	Electric generating facilities				3,055			2,735
	Gas transmission assets				1,519			1,512
	Land				132			131
	Other				167			163
	Construction work in progress				2,146			2,100
		Total property, plant and equipment (at original cost)			7,019			6,641
	Accumulated depreciation				(927	)		(887	)
		Net property, plant and equipment			6,092			5,754
OTHER NONCURRENT ASSETS
	Long-term receivables				434			455
	Long-term receivables from PG&E Corporation				174			174
	Investments in unconsolidated affiliates				424			414
	Goodwill, net of accumulated amortization of $30 million				95			95
	Intangible assets, net of accumulated amortization of $20 million and $19 million, respectively				85			85
	Deferred financing costs, net of accumulated amortization of $11 million and $6 million, respectively				75			79
	Price risk management				354			302
	Other				351			333
		Total other noncurrent assets			1,992			1,937
TOTAL ASSETS				$	10,669		$	10,329

3

PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(In Millions)

				BALANCE AT
				March 31,			December 31,
				2002			2001
LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
	Short-term borrowings			$	406		$	330
	Long-term debt, classified as current				48			48
	Obligations due related parties and affiliates				309			309
	Accounts payable:
		Trade			831			957
		Related parties			42			41
	Accrued expenses				343			336
	Price risk management				445			277
	Out-of-market contractual obligations				114			116
	Other				150			97
			Total current liabilities		2,688			2,511
NONCURRENT LIABILITIES
	Long-term debt				3,557			3,374
	Deferred income taxes				639			681
	Price risk management				362			310
	Out-of-market contractual obligations				680			683
	Long-term advances from PG&E Corporation				118			118
	Other noncurrent liabilities and deferred credits				71			65
			Total noncurrent liabilities		5,427			5,231
MINORITY INTEREST					20			20
COMMITMENTS AND CONTINGENCIES(Note 5)					—			—
PREFERRED STOCK OF SUBSIDIARY					58			58
COMMON STOCKHOLDERS’ EQUITY
	Common stock, $1.00 par value—1,000 shares issued and outstanding				—			—
	Paid-in capital				3,086			3,086
	Accumulated deficit				(573	)		(610	)
	Accumulated other comprehensive income (loss)				(37	)		33
			Total common stockholders’ equity		2,476			2,509
TOTAL LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY				$	10,669		$	10,329

The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.

4

PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In Millions)

				Three Months Ended
				March 31,
							As revised, see
							Note 1
				2002			2001
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income			$	37		$	54
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization			48			38
		Deferred income taxes			(37	)		(42	)
		Price risk management assets and liabilities — net			21			3
		Amortization of out-of-market contractual obligation			(31	)		(37	)
		Other deferred credits and noncurrent liabilities			6			(1	)
		Equity in earnings of affiliates			(18	)		(26	)
		Distribution from affiliates			7			8
	Net effect of changes in operating assets and liabilities:
		Restricted cash			(12	)		(7	)
		Accounts receivable—trade			224			1,200
		Inventories, prepaids and deposits			(121	)		(4	)
		Accounts payable and accrued liabilities			(119	)		(1,258	)
		Accounts payable—related parties – net			4			(25	)
		Other, net			75			(95	)
			Net cash provided by (used in ) operating activities		84			(192	)
CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures				(378	)		(181	)
	Long-term prepayment on turbines				—			(73	)
	Other—net				1			(11	)
			Net cash used in investing activities		(377	)		(265	)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Net borrowings under credit facilities				76			16
	Long-term debt issued				190			199
	Long-term debt matured, redeemed, or repurchased				(7	)		(49	)
			Net cash provided by financing activities		259			166
NET CHANGE IN CASH AND CASH EQUIVALENTS					(34	)		(291	)
CASH AND CASH EQUIVALENTS, AT January 1					725			738
CASH AND CASH EQUIVALENTS, AT March 31				$	691		$	447
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
	Cash paid for:
		Interest, (net of amount capitalized)		$	42		$	43
		Income taxes paid, (refunded) – net			8			—
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING:
	Long-term debt related to the purchase of Attala Generating Company				—			(29	)
	Change in other comprehensive (income) loss due to No. SFAS 133, net of deferred taxes				70			(72	)
	Change in equity investment due to SFAS No. 133				2			(2	)
	Transfer of assets from long-term prepaid to construction in progress				—			(67	)

The accompanying Notes to the Consolidated Financial Statements are an integral part of this statement.

5

PG&E NATIONAL ENERGY GROUP, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1: GENERAL

Organization and Basis of Presentation

PG&E National Energy Group, Inc. was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E National Energy Group, Inc. PG&E National Energy Group, Inc. is an indirect wholly owned subsidiary of PG&E Corporation. PG&E National Energy Group, Inc. and its subsidiaries (PG&E NEG) are principally located in the United States and Canada and are engaged in power generation and development, wholesale energy marketing and trading, risk management, and natural gas transmission. PG&E NEG’s principal subsidiaries include: PG&E Generating Company, LLC, and its subsidiaries (collectively, PG&E GenLLC); PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, 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). PG&E NEG also has other less significant subsidiaries.

The consolidated financial statements of PG&E NEG include the accounts of PG&E NEG and its wholly owned and controlled subsidiaries. All significant inter-company transactions have been eliminated from the unaudited consolidated financial statements. 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 such investments in affiliated entities, which include corporations, limited liability companies and partnerships, due to the ownership structure preventing PG&E NEG from exercising control. Under this method, PG&E NEG’s share of equity income or losses of these entities is reflected as equity in earnings of affiliates. Additionally, PG&E NEG has also consolidated certain special purpose entities as required by Accounting Principles Generally Accepted in the United States (GAAP), although PG&E NEG has no legal ownership of those entities.

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 Report on Form 10-Q. Certain amounts in the prior year’s unaudited Consolidated Financial Statements have been reclassified to conform to the 2002 presentation. 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 2001 Annual Report on Form 10-K and its other reports filed with the Securities and Exchange Commission (SEC) since the 2001 Form 10-K 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 revenue, expenses, assets and liabilities, and the disclosure of contingencies. Actual results could differ from these estimates.

6

Revision Footnote

Subsequent to the issuance of PG&E NEG’s registration statement on Form S-4 filed with the SEC on July 27, 2001 and amended on August 21, 2001, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2001. A summary of the significant effects of the revisions to the Consolidated Statements of Operations and Consolidated Statements of Cash Flows is as follows (in millions):

		Three Months Ended March 31, 2001
		As
		Previously			As
		Reported			Revised
CONSOLIDATED STATEMENTS OF OPERATIONS
Generation, transportation, and trading		$	4,182		$	4,180
	Total operating revenues		4,208			4,206
Operations, maintenance, and management			128			126
	Total operating expenses		4,123			4,121
CONSOLIDATED STATEMENTS OF CASH FLOWS
Capital expenditures		$	(68	)	$	(181	)
Long-term prepayment on turbines			—			(73	)
Long-term debt issued			—			199

Comprehensive Loss

Comprehensive loss reports a measure for changes in income of an enterprise that result from transactions and other economic events other than transactions with shareholders. PG&E NEG’s comprehensive loss consists principally of changes in the market value of certain cash flow hedges with the implementation of SFAS No. 133 on January 1, 2001.

(in millions)
Three months ended March 31, 2002
Net income	$	37
Net loss from current period hedging transactions and price changes in accordance with SFAS No. 133		(75	)
Net reclassification to earnings		5
Comprehensive loss	$	(33	)
Three months ended March 31, 2001
Net income	$	54
Cumulative effect of adoption of SFAS No. 133		(333	)
Net loss from current period hedging transactions and price changes in accordance with SFAS No. 133		(30	)
Net reclassification to earnings		100
Comprehensive loss	$	(209	)

7

Significant Accounting Policies

Except as disclosed below, PG&E NEG has not adopted or changed any accounting principles.

On January 1, 2002, PG&E NEG adopted SFAS No. 142, “Goodwill and Other Intangible Assets.” This Statement eliminates the amortization of goodwill, and requires that goodwill be reviewed at least annually for impairment. Implementation of this Statement did not have any impact on the statement of position or results of operations. The amount of goodwill amortization expense for March 31, 2001 was $1 million. Prospective elimination of goodwill amortization will not have a significant impact on the consolidated financial statements.

This Statement also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods be adjusted accordingly. Adoption of this Statement did not require any adjustments to be made to the useful lives of existing intangible assets and no reclassifications of intangible assets to goodwill were necessary.

Intangible assets are being amortized on a straight-line basis over their estimated useful lives and are reported under intangible assets in the Consolidated Balance Sheets.

The schedule below summarizes the amount of intangible assets by major classes (in millions):

	Balance at
	March 31, 2002				December 31, 2001
	Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amount		Amortization		Amount		Amortization
Service agreements	$	33	$	6	$	33	$	6
Power sale agreements		44		8		44		8
Other agreements		28		6		27		5
Total	$	105	$	20	$	104	$	19

The schedule below shows the aggregate amortization expense for the periods (in millions):

	Three Months Ended
	March 31
	2002		2001
Amortization expense	$	1	$	1

The following schedule shows the estimated amortization expenses of intangible assets for the next five years (in millions):

2002	2003		2004		2005		2006
$6	$	6	$	6	$	6	$	6

On January 1, 2002, PG&E NEG adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of”, but retains the fundamental provision for recognizing and measuring impairment of long-lived assets to be held and used or disposed of by sale. The Statement also supersedes the accounting and reporting provision for the disposal of a segment of a business. SFAS No. 144 eliminates the conflict between accounting models for treating the disposition of long-lived assets that existed between SFAS No. 121 and the guidance for a segment of a business accounted for as a discontinued operation by adopting the methodology established in SFAS No. 121, and also resolves implementation issues related to SFAS No. 121. The adoption of the Statement did not have any impact on the consolidated financial statements of PG&E NEG.

8

Related Party Transactions

On October 26, 2000, PG&E NEG loaned $75 million to PG&E Corporation pursuant to a promissory note. The principal amount is payable upon demand and is included in Long-term receivable from PG&E Corporation on the consolidated balance sheets. The balance at March 31, 2002 remains at $75 million.

As of March 31, 2002 and 2001, PG&E Corporation had issued a $16 million guarantee for an office lease relating to PG&E NEG’s San Francisco office.

As of March 31, 2002 and 2001, Attala Power Corporation (APC), an indirect, wholly-owned subsidiary of the PG&E NEG, has a non-recourse demand note payable to the PG&E Corporation of $309 million. The APC note is classified as short-term on the Consolidated Balance Sheets, as of March 31, 2002. The demand note between APC and PG&E Corporation is recourse only to APC and not to PG&E NEG.

In addition, as of March 31, 2002, other wholly owned subsidiaries of PG&E NEG had net amounts payable in the amount of $122 million in the form of promissory notes to PG&E Corporation related primarily to past funding of generating asset development and acquisition, of which $118 million was classified as long-term on the Consolidated Balance Sheets. Furthermore, as of March 31, 2002, PG&E NEG has recorded a $99 million receivable from PG&E Corporation related to the intercompany tax-sharing arrangement; this amount is included in Long-term receivables from PG&E Corporation, in the accompanying Consolidated Balance Sheets.

PG&E ET enters into transactions with related parties, including the Pacific Gas and Electric Company (the Utility). The nature of these transactions is the purchasing and selling of energy commodities and general corporate business items. For the three months ended March 31, 2002 and 2001, PG&E ET had energy commodity sales of approximately $19.7 million and $74.6 million, respectively, to the Utility, and energy commodity purchases of $2.2 million and $3.0 million, respectively. As of March 31, 2002, PG&E ET had trade receivables relating to energy commodity transactions from the Utility of $27.4 million, and trade payables relating to energy commodity transactions to the Utility of $0.9 million. The Utility is current on amounts owed to PG&E ET arising after April 6, 2001.

For the three months ended March 31, 2002 and 2001, the Utility accounted for approximately $11.5 million and $8.7 million of PG&E GTN’s transportation revenues. As a result of the Utility’s April 6, 2001, filing of a voluntary petition under Chapter 11 of the U.S. Bankruptcy Code, all $2.9 million due from the Utility to PG&E GTN on that date remains outstanding. 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.

PG&E NEG and its affiliates are charged for administrative and general costs from PG&E Corporation. These charges are based upon direct assignment of costs and allocations of costs using allocation methods that PG&E NEG and PG&E Corporation believe are reasonable reflections of the utilization of services provided to or for the benefits received by PG&E NEG. For the three months ended March 31, 2002 and 2001, allocated costs totaled $6.3 million and $7.6 million, respectively. The total amount due PG&E Corporation at March 31, 2002, was $28.4 million.

In addition, PG&E NEG bills PG&E Corporation for certain shared costs. For the three months ended March 31, 2002 and 2001, the total charges billed to PG&E Corporation were $0.7 million and $0.5 million, respectively. The amounts receivable from PG&E Corporation at March 31, 2002, was $1.8 million.

NOTE 2. RELATIONSHIP WITH PG&E CORPORATION AND THE CALIFORNIA ENERGY CRISIS

For periods prior to 2001, PG&E Corporation provided financial support in the form of direct lending activities with PG&E NEG, and provision of collateral to third parties to support PG&E NEG’s contractual commitments and daily operations. Funds from operations were managed through net investments or borrowings in a pooled cash management arrangement, and PG&E Corporation provided credit support for trading activities through PG&E Corporation’s guarantees and surety bonds. Certain development and construction activities were funded in part

9

through PG&E Corporation’s equity contributions or secured using instruments such as PG&E Corporation’s guarantees or equity commitments. PG&E Corporation also assisted with financing activities through short-term demand borrowings and long-term notes between PG&E Corporation and PG&E NEG and PG&E Corporation’s guarantees of certain minor credit facilities. Furthermore, PG&E NEG, PG&E Corporation and another affiliate of PG&E Corporation share the costs of certain administrative and general functions.

In December 2000, and in January and February 2001, PG&E Corporation and PG&E NEG completed a corporate restructuring that involved the use or creation of limited liability companies (LLCs) as intermediate owners between a parent company and its subsidiaries. These LLCs are PG&E National Energy Group, LLC which owns 100 percent of the stock of PG&E NEG, GTN Holdings LLC which owns 100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC which owns 100 percent of the stock of PG&E ET. In addition, PG&E NEG’s organizational documents were modified to include the same structural elements as the LLCs. The LLCs 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 LLCs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and PG&E NEG meets specified financial requirements. After the restructuring was completed, two independent rating agencies, Standard & Poor’s (S&P) and (Moody’s) Investor Services reaffirmed investment grade ratings for PG&E GTN and PG&E GenLLC, and issued investment grade ratings for PG&E NEG. S&P also issued an investment grade rating for PG&E ET.

The FERC issued a letter order granting approval of the corporate restructuring on January 12, 2001. Thereafter, requests for rehearing and requests to vacate that order were filed with the FERC, each of which was denied by the FERC on February 21, 2001. Requests for rehearing of the February 21 order were filed. On January 30, 2002, the FERC issued an order denying all pending petitions for rehearing. On February 21, 2002, the California Attorney General, the Public Utilities Commission of the State of California and the Northern California Power Agency petitioned the United States Court of Appeals for the Ninth Circuit for a review of the FERC’s orders.

On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court). Pursuant to the Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The Utility and PG&E Corporation have jointly filed a plan of reorganization with the Bankruptcy Court that entails separating the Utility into four distinct businesses. The proposed plan of reorganization does not directly affect PG&E NEG or any of its subsidiaries. Subsequent to the bankruptcy filing, the investment grade ratings of PG&E NEG and its rated subsidiaries were reaffirmed on April 6 and 9, 2001.

Management believes that PG&E NEG and its direct and indirect subsidiaries, as described above, would not be substantively consolidated with PG&E Corporation in any insolvency or bankruptcy proceeding involving PG&E Corporation or the Utility.

As of December 31, 2001, PG&E NEG had replaced or eliminated all of the previously issued PG&E Corporation guarantees (except for a $16 million office lease guarantee relating to PG&E NEG’s San Francisco office) with a combination of guarantees provided by PG&E NEG or its subsidiaries and letters of credit obtained independently by PG&E NEG.

NOTE 3. PRICE RISK MANAGEMENT

PG&E NEG’s net gain (loss) on trading activities, recognized on a fair value basis, were as follows (in millions):

	Three months ended
	March 31,
	2002			2001
Trading activities:
Unrealized loss, net	$	(3	)	$	(46	)
Realized gain, net		45			74
Total	$	42		$	28

10

PG&E NEG’s ineffective portion of changes in fair values of cash flow hedges was immaterial for the three months ended March 31, 2002 and 2001. PG&E NEG’s estimated net derivative gains or losses included in accumulated other comprehensive income (loss) at March 31, 2002, that are expected to be reclassified into earnings within the next 12 months are net losses of $31 million. The actual amounts reclassified from accumulated other comprehensive loss to earnings can differ as a result of market price changes. As of March 31, 2002, the maximum length of time over which PG&E NEG had hedged its exposure to the variability in future cash flows associated with commodity price risk is through December 2010. The maximum length of time over which PG&E NEG has hedged its exposure to the variability in future cash flows associated with interest rate risk is through March 2014.

The schedule below summarizes the activities affecting accumulated other comprehensive income (loss), net of tax, from derivative instruments for the three months ended March 31, 2002, (in millions):

Derivative net gains included in accumulated other comprehensive income at January 1	$	36
Net loss from current period hedging transactions and price changes		(75	)
Net reclassification to earnings		5
Derivative net losses included in accumulated other comprehensive loss at March 31		(34	)
Foreign currency translation adjustment		(3	)
Accumulated other comprehensive loss at March 31	$	(37	)

11

Credit Risk

Credit risk is the risk of loss that PG&E NEG would incur if counterparties fail to perform their contractual obligations. PG&E NEG conducts business primarily with customers in the energy industry, such as investor-owned and 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 in that its counterparties may be similarly affected by changes in economic, regulatory, or other conditions. PG&E NEG mitigates potential credit losses in accordance with established credit approval practices and limits by dealing primarily with creditworthy counterparties (counterparties considered investment grade or higher). PG&E NEG reviews credit exposure in relation to specified counterparty limits daily and to the maximum extent possible, requires that all derivative contracts take the form of master agreements which contain credit support provisions that require the counterparty to post security 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 as the current mark-to-market value (what would be lost if the counterparty defaulted today) plus any outstanding net receivables, prior to the application of credit collateral. In the past year, PG&E NEG’s credit risk has increased partially due to credit rating downgrades of some of the counterparties in the energy industry to below investment grade. As of March 31, 2002, PG&E NEG’s only customer greater than 10 percent of its total credit exposure was the State of California Department of Water Resources (DWR), which represented 13 percent of PG&E NEG’s credit exposure.

The schedule below summarizes the exposure to counterparties that are in a net asset position, with the exception of written options and exchange-traded futures (the exchange provides for contract settlement on a daily basis) as of March 31, 2002 (in millions):

Gross	Credit
Exposure(1)	Collateral(2)		Net Exposure(2)
$786	$	90	$	696

(1)	Gross credit exposure equals mark-to-market value plus net (payables) receivables where netting is allowed.
(2)	Net exposure is the gross exposure minus credit collateral (cash deposits and letters of credit). Amounts are not adjusted for probability of default.

The majority of counterparties to which PG&E NEG is exposed are considered to be of investment grade, determined using publicly available information including an S&P rating of at least BBB-. PG&E NEG’s net credit exposure to below investment grade entities, consisting principally of Southern California Edison, DWR, and Pacific Gas and Electric Company, aggregates to approximately $230 million or 33 percent. PG&E NEG’s concentration of credit exposure is to counterparties that conduct business primarily in North America.

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NOTE 4. DEBT FINANCING

On April 5, 2002, GenHoldings I, LLC increased its committed financing from $1.075 billion to $1.460 billion. The increase in the facility provides for additional borrowing capacity and will provide funding for, and be secured by, an additional project, Covert Generating, located in Michigan, which is currently under construction. No other terms of the facility were changed.

In April 2002, PG&E GTN received commitments from several financial institutions for a new three-year revolving credit agreement of up to $125 million to replace the existing revolving credit agreement. PG&E GTN expects to complete such financing in May 2002. PG&E GTN also plans to obtain additional long-term financing in the near future and has obtained a commitment from a financial institution for a backup 364-day bank facility if PG&E GTN decides to postpone such long-term financing.

NOTE 5. COMMITMENTS AND CONTINGENCIES

Commitments

PG&E NEG has financial commitments in connection with agreements entered into supporting its construction and development activities. These commitments are discussed more fully in the Annual Report on Form 10-K. Certain of these commitments are supported by letters of credit. Below is a listing of the outstanding letters of credit and discussion of other commitments and contingencies.

Letters of Credit:The following table provides the various letter of credit facilities which have the capacity to issue letters of credit (in millions):

							Letters of Credit
							Outstanding
Borrower	Maturity			Letter of Credit Capacity			March 31, 2002
PG&E NEG		8/02&8/03			$	650	$	197
USGenNE		9/03			$	50	$	9
PG&E GenLLC		12/04			$	10	$	7
PG&E ET		12/02			$	25	$	19
PG&E ET		--	(1)		$	50	$	22
PG&E ET		11/03			$	35	$	32

(1)  This letter of credit facility provides for up to $50 million of letters of credit to be issued, available to PG&E Energy Trading, Canada Corporation, an indirect subsidiary of PG&E NEG, to use to post non-domestic letters of credit to support counterparty trading, for periods no longer than 364 days. There is no term for the facility, but the bank can review for termination each year.

Contingencies

Guarantees Supporting Tolling Agreements- A subsidiary of PG&E NEG has entered into five long-term tolling transactions with third parties. Each tolling agreement is supported by a separate guarantee backing the PG&E NEG affiliate’s payment obligations over the term of these long-term contracts (9-25 years). PG&E NEG has extended approximately $620 million of such guarantees with the initial face value varying from $20 million to $250 million declining over time as the future obligation declines. Each of these guarantees contains a trigger event provision that requires the guarantor to replace the guarantee or provide alternative collateral in the event that the PG&E NEG credit rating drops (as measured by one or two major agencies as identified in the agreement) below the prescribed

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grade (generally BBB or Baa2). As of March 31, 2002, net exposure under guarantees supporting tolling agreements was approximately 3% or $20 million.

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

In addition to issuing guarantees supporting tolling agreements, as of March 31, 2002, PG&E NEG and its subsidiaries provided $2.7 billion of guarantees to counterparties in support of its energy trading operations. This includes provision of fuel and pipeline capacity to, and sale of energy products from its power plants. These guarantees were provided in favor of approximately 230 counterparties to permit and facilitate physical and financial transactions in gas, pipeline capacity, power, coal, and related commodities and services with these entities. Typically, the overall exposure under these guarantees is only a fraction of the face value of the guarantees, since not all counterparty credit limits are fully utilized at any time and there may be no outstanding transactions or financial exposure underlying an outstanding guarantee. PG&E NEG receives similar deposits, letters of credit, and guarantees as collateral for credit extended by PG&E NEG to these, in many cases, same counterparties. These offsetting exposures can often be netted in lieu of posting alternative collateral. As of March 31, 2002, PG&E NEG’s net exposure under its guarantees was approximately 9 percent or approximately $260 million. This exposure is a contingent obligation that could be called only if PG&E NEG or one of its subsidiaries fails to meet a payment obligation.

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

The amount of exposure under master agreements subject to securitization requirements in the event of a credit downgrade of PG&E NEG or its subsidiaries to below investment grade by one or more rating agencies was approximately 5 percent of the outstanding guarantees or approximately $144 million at March 31, 2002. PG&E NEG manages this risk through maintenance of investment grade credit ratings at several principal operating subsidiaries so that guarantees of one entity could be substituted for another in the event of a credit downgrade of one entity.

Guarantees Supporting Other Agreements with Third Parties—PG&E NEG and its subsidiaries have issued in excess of $720 million of guarantees in support of various obligations under agreements with third parties. Of these guarantees supporting other agreements with third parties, $486 million have investment grade ratings maintenance requirements. In addition, a number of other agreements have specific security provisions requiring maintenance of investment grade ratings. In the event of a downgrade below the trigger level and exhaustion of any cure period, some of these agreements would allow the counterparty to demand payment for any outstanding obligations or contract termination penalties, if any. Others simply provide the counterparty with a right to terminate the contract.

Environmental Matters- 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 the PG&E NEG’s Brayton Point and Salem Harbor Generating Stations with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had very preliminary discussions with the EPA to explore a potential settlement of this matter. Management believes that it is not

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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 this and related regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring initiatives that would assist USGenNE to achieve significant reductions of sulfur dioxide and nitrogen oxide emissions by 2006. Additional requirements for the control of mercury and carbon dioxide emissions will also 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 will approximate $290 million over the next five years. The Massachusetts Department of Environmental Protection (DEP) may require earlier compliance, which USGenNE believes may not be feasible and would require the use of credit allowances it currently owns or the purchase of additional credit allowances.

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. On April 5, 2002, EPA promulgated a regulation that extends this deadline for the case-by-case permits until May 2004. 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 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 it is anticipated that all three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. Those three facilities are Salem Harbor, Manchester Street and Brayton Point. It is estimated that USGenNE’s cost to comply with the new permit conditions could be as much as $67 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits and that the cost to comply with the new permit conditions could be substantially greater than that amount.

On March 27, 2002, Rhode Island Attorney General Sheldon Whitehouse, notified USGenNE, of his belief that the company’s Brayton Point Station “is in violation of applicable statutory and regulatory provisions governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into Mt. 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. The notice purportedly was provided pursuant to section 7A of chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point Station is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. PG&E NEG is currently awaiting the issuance of a draft Clean Water Act NPDES permit renewal from the EPA. Management is unable to predict whether the ultimate outcome of this matter will have a material adverse affect on PG&E NEG's financial condition or results of operations.

Additionally, 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 (mgd), typically including some form of “once-through” cooling. The Brayton Point, Salem Harbor, and Manchester Street Stations 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 which are intended to reduce impacts to aquatic organisms. Significant capital investment will likely be required to achieve the standards if the regulations are finalized as proposed. The final rules are scheduled for promulgation in August 2003.

During April 2000, an environmental group served USGenNE and other of 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 2002. PG&E NEG incurred expenditures related to these agreements of approximately $5.8 million in 2000 and $2.4 million in 2001. In addition to the costs incurred in 2000 and 2001, at December 31, 2001, PG&E NEG maintains a reserve in the amount of $10.0 million relating to its estimate of the remaining environmental expenditures to fulfill its obligations under

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these agreements. PG&E NEG has deferred costs associated with capital expenditures and has set up a receivable for amounts it believes are probable of recovery from insurance proceeds.

PG&E NEG anticipates spending up to approximately $363 million, net of insurance proceeds, through 2008 for environmental compliance at currently operating facilities. PG&E NEG believes that a substantial portion of this amount will be funded from its operating cash flow. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG.

Legal Matters- In addition to the following legal proceedings, PG&E NEG is subject to routine litigation incidental to its business.

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 which 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, USGen New England, the entity that owns the generating assets located in NEPOOL, have had their market-based rate authority confirmed by 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). 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 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.

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. On July 25, 2001 the 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. Based on its interpretation of the FERC’s methodology, the California Independent System Operator (California ISO) has indicated that

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PG&E ET-Power may be required to refund approximately $26 million. This figure depends significantly on the assumptions underlying the calculation of hourly proxy competitive prices or mitigated market clearing prices that may be used as a basis for establishing refunds. Using a slightly different set of assumptions that we believe more accurately reflect the FERC’s methodology, the amount of refund could be significantly less. On December 19, 2001, the FERC issued a decision purporting to clarify its earlier orders. The California ISO has provided an update of its August 17, 2001 data and a hearing is now scheduled to take place before a FERC administrative law judge this summer to determine refund amounts and additional amounts owed. In addition, the FERC has indicated that unpaid amounts owed by the California ISO and California Power Exchange may be used as offsets to any refund obligations. PG&E NEG estimates that PG&E ET-Power is currently owed approximately $22 million that could be used as offsets to certain potential refund obligations. Finalization of all these amounts will be subject to the on-going FERC proceeding. PG&E NEG believes that the ultimate outcome of this matter will not have a material adverse affect on the 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 the ultimate outcome of the litigation will not have a material adverse affect on its 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. 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 ISO-New England expenses, uplift charges and congestion costs. NEPCo and Narragansett are currently paying the charges under an agreement which expires by its terms on April 30, 2003, unless extended by mutual agreement. The Tolling Agreement does not prohibit either party from undertaking proceedings to decide on the allocation issues. The FERC has rejected certain attempts by NEPCo to affirmatively transfer these obligations on a going forward basis by means of NEPOOL market rules and procedures but the FERC has consistently refused to insert itself in the contractual dispute. In a letter dated August 31, 2001, distribution company affiliates of NEPCo informed USGenNE that they are invoking the dispute resolution provisions of the WSOS Agreements and that they will seek reimbursement of $27 million for amounts incurred to date along with a ruling that under the WSOS Agreements these costs should be imposed on USGenNE going forward. These going forward costs are estimated to be approximately $18 million. On March 27, 2002, the parties formally commenced arbitration. PG&E NEG believes that the ultimate outcome of this litigation will not have a material adverse effect on the Company’s financial condition or results of operations.

Brayton Point- On March 27, 2002, Rhode Island Attorney General Sheldon Whitehouse, notified USGenNE, of his belief that the company’s Brayton Point Station “is in violation of applicable statutory and regulatory provisions

17

governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into Mt. 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. The notice purportedly was provided pursuant to section 7A of chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point Station is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. PG&E NEG is currently awaiting the issuance of a draft Clean Water Act NPDES permit renewal from the EPA. Management is unable to predict whether the ultimate outcome of this matter will have a material adverse affect on PG&E NEG's financial condition or results of operations.

California Attorney General Complaint- On March 20, 2002 the California Attorney General filed a complaint at FERC against ET-Power and other named and unnamed public utility sellers of energy and ancillary services. State of Californiaex rel.Bill Lockyer, Docket No. EL02-71-000. The Attorney General alleges that wholesale sellers of energy to the California ISO, PX and CDWR failed to file their rates in accordance with the requirements of Section 205 of the Federal Power Act. Specifically, the California Attorney General claims that FERC has not been able to determine whether the rates charged by such sellers are just and reasonable; that FERC’s reporting requirements are not sufficient to allow the Commission the information necessary to make this determination and that even if FERC’s policies and procedures did comply with Section 205 of the Federal Power Act, the wholesale sellers failed to comply with its quarterly reporting requirements. As a result, the California Attorney General requests that: (1) sellers should be directed to comply, on a prospective basis, with the requirements of Section 205 of the Federal Power Act; (2) sellers should be required to provide transaction-specific information regarding their short-term sales to the ISO, PX and CDWR for the years 2000 and 2001 to the FERC; (3) if rates were charged that were not just and reasonable, refunds should be ordered; (4) the Commission should declare that market-based rates are not subject to the filed rate doctrine; and (5) the Commission should institute proceedings to determine whether any further relief would be appropriate. PG&E NEG believes that the outcome of this matter will not have a material adverse affect on PG&E NEG’s financial condition or results of operations.

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NOTE 6. SEGMENT INFORMATION

PG&E NEG is currently managed under 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 key decision makers. The first business segment is composed of PG&E NEG’s Integrated Energy and Marketing Activities (PG&E Energy), principally the generation and energy trading operations, which are managed and operated in a highly integrated manner. The second business segment is PG&E NEG’s Interstate Pipeline Operations (PG&E Pipeline).

Segment information for the three months ended March 31, 2002, and 2001 was as follows (in millions):

	Integrated Energy and		Interstate Pipeline		Other and
	Marketing Activities		Operations		Eliminations(2)			Total
Three Months Ended March 31, 2002
Operating revenues	$	2,273	$	59	$	(2	)	$	2,330
Intersegment revenues(1)		2		—		(2	)		—
Equity in earnings of affiliates		18		—		—			18
Total operating revenues		2,293		59		(4	)		2,348
Net income		26		18		(7	)		37
Total assets at March 31, 2002	$	9,212	$	1,290	$	167		$	10,669
Three Months Ended March 31, 2001(3)
Operating revenues	$	4,124	$	65	$	(9	)	$	4,180
Intersegment revenues(1)		—		—		—			—
Equity in earnings of affiliates		26		—		—			26
Total operating revenues		4,150		65		(9	)		4,206
Net income		35		20		(1	)		54
Total assets at March 31, 2001	$	11,833	$	1,188	$	231		$	13,252

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

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

     (3)  As revised, See Note 1.

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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

PG&E National Energy Group, Inc. is an integrated energy company with a strategic focus on power generation, natural gas transmission and wholesale energy marketing and trading in North America. PG&E National Energy Group, Inc. and its subsidiaries (collectively, PG&E NEG) have integrated their generation, development and energy marketing and trading activities in an effort to create energy products in response to customer needs, increase the returns from operations and identify and capitalize on opportunities to optimize generating and pipeline capacity. PG&E National Energy Group, Inc. was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to the PG&E NEG. PG&E NEG’s principal subsidiaries include: PG&E Generating Company, LLC and its subsidiaries (collectively, PG&E GenLLC); PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, PG&E ET); PG&E Gas Transmission Corporation and its subsidiaries (collectively, PG&E GTC), which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively, PG&E GTN), and North Baja Pipeline, LLC (NBP). PG&E NEG also has other less significant subsidiaries.

In December 2000, and in January and February 2001, PG&E Corporation and PG&E NEG completed a corporate restructuring of PG&E NEG, involving the creation of limited liability companies (LLCs) as intermediate owners between a parent company and its subsidiaries. The LLCs formed were PG&E National Energy Group, LLC which owns 100 percent of the stock of PG&E NEG, GTN Holdings LLC which owns 100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC which owns 100 percent of the stock of PG&E ET. In addition, PG&E NEG’s organizational documents were modified to include the same structural elements as the LLCs. The LLCs 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 LLCs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and PG&E NEG meets specified financial requirements.

PG&E NEG reports its business in two business segments, interstate pipeline operations (PG&E Pipeline) and integrated energy and marketing (or PG&E Energy). PG&E Pipeline is comprised of PG&E GTC, which includes PG&E GTN and NBP. PG&E Energy is comprised of PG&E GenLLC and PG&E ET, which owns PG&E Energy Trading-Power, L.P. and PG&E Energy Trading-Gas Corporation and other affiliates.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the consolidated financial statements included herein. Further, this quarterly report should be read in conjunction with PG&E NEG’s Consolidated Financial Statements and Notes to the Consolidated Financial Statements included in PG&E NEG’s 2001 Annual Report on Form 10-K.

This Quarterly Report on Form 10-Q includes forward-looking statements that are necessarily subject to various risk 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,” 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 those expressed or implied by the forward-looking statements, or historical results include:

• The volatility of commodity fuel and electricity prices (which may result from a variety of factors, including: weather; the supply and demand for energy commodities; the availability of competitively priced alternative energy sources; the level of production and availability of natural gas, crude oil, and coal; transmission or transportation constraints; federal and state energy and environmental regulation and legislation; the degree of market liquidity; and natural disasters, wars,

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

	embargoes, and other catastrophic events); any resulting increases in the cost of producing power and decreases in prices of power sold, and whether PG&E NEG’s strategies to manage and respond to such volatility are successful;
•	The extent and timing of generating, pipeline, and storage capacity expansion and retirements by others;
•	Future sales levels, and general economic and financial market conditions, and changes in interest rates;
•	The extent to which PG&E NEG’s current or planned development of generation, pipeline, and storage facilities are completed and the pace and cost of that completion, including the extent to which commercial operations of these development projects are delayed or prevented because of various development and construction risks such as PG&E NEG’s failure to obtain necessary permits or equipment, the failure of third-party contractors to perform their contractual obligations, or the failure of necessary equipment to perform as anticipated;
•	The performance of PG&E NEG projects and the success of PG&E NEG’s efforts to invest in and develop new opportunities;
•	PG&E NEG's ability to obtain financing from third parties or from PG&E Corporation for PG&E NEG’s planned development projects and related equipment purchases and to refinance PG&E NEG’s subsidiaries’ existing indebtedness as it matures, in each case, on reasonable terms, while preserving PG&E NEG’s credit quality; which ability could be negatively affected by conditions in the general economy, the energy or capital markets; and the extent to which the CPUC’s holding company conditions may be interpreted to restrict PG&E Corporation’s ability to provide financial support to us;
•	Heightened rating agency criteria and the impact of changes in credit ratings on PG&E NEG’s future financial condition, particularly a downgrade below investment grade which would impair PG&E NEG’s ability to meet liquidity calls in connection with PG&E NEG’s trading activities and obtain financing for PG&E NEG’s planned development projects;
•	Volatility resulting from mark-to-market accounting and the extent to which the assumptions underlying PG&E NEG’s mark-to market accounting and risk management programs are not realized;
•	The effect of new accounting pronouncements;
•	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;
•	The effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;
•	Restrictions imposed upon PG&E Corporation and us under certain term loans of PG&E Corporation;
•	The effect of the Utility bankruptcy proceedings upon PG&E Corporation and upon PG&E NEG; and in particular, the impact a protracted delay in the Utility’s bankruptcy proceedings could have on PG&E Corporation’s liquidity and access to capital markets;

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

• The outcomes of the CPUC’s pending investigation into whether the California investor-owned utilities and their parent holding companies, including PG&E Corporation, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations; the outcomes of the lawsuits brought by the California Attorney General, the City and County of San Francisco, and People of the State of California against PG&E Corporation alleging unfair or fraudulent business acts or practices based on alleged violations of conditions established in the CPUC’s holding company decisions; 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 Corporation and PG&E NEG; and

• The extent to which the CPUC's holding company conditions may be interpreted to restrict PG&E Corporation's ability to provide financial support to PG&E NEG; and

• The outcome of pending litigation and environmental matters.

Interstate Pipeline Operations

PG&E NEG owns, operates and develops natural gas pipeline facilities. PG&E GTN consists of over 1,350 miles of natural gas transmission pipeline with a capacity of approximately 2.7 billion cubic feet of natural gas per day. This pipeline is the only interstate pipeline directly linking the natural gas reserves in Western Canada to the gas markets of California and parts of the Pacific Northwest. An expansion of this pipeline currently under construction will, when completed, increase capacity by an additional 217 MMcf per day. Approximately 40 MMcf per day of capacity associated with this expansion was operational in the fourth quarter of 2001. The remaining volumes are expected to be operational in the fourth quarter of 2002. PG&E GTN filed in November 2001 to expand capacity further by approximately 150 MMcf per day. PG&E NEG began construction of the North Baja pipeline, which will run from Arizona to Northern Mexico, in the first quarter of 2002. The North Baja pipeline is expected to have an initial certificated capacity of 500 MMcf per day and is expected to become operational by late 2002.

In addition, PG&E NEG owns a 5.2 percent interest in the Iroquois Gas Transmission System, an interstate pipeline which extends 375 miles from the U.S.-Canadian border in northern New York through the State of Connecticut to Long Island, New York. This pipeline, which commenced operations in 1991, provides gas transportation service to local gas distribution companies, electric utilities and electric power generators, directly or indirectly through exchanges and interconnecting pipelines, throughout the Northeast.

Integrated Energy and Marketing Business

PG&E NEG engages in the generation, transport, marketing and trading of electricity, various fuels and other energy-related commodities throughout North America. PG&E NEG aggregates electricity and related products from its owned, leased or controlled generating facilities and through PG&E NEG’s marketing and trading positions. PG&E NEG manages the fuel supply and sale of electrical output from all these positions in an integrated portfolio. The objective of PG&E NEG’s integrated approach is to enable PG&E NEG to effectively manage its exposure to commodity price and counterparty credit risk. As of March 31, 2002, PG&E NEG had ownership or leasehold interests in 25 operating generating facilities with a net generating capacity of 6,518 megawatts (MW), as follows:

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

	Net		Primary	% of
Number of Facilities	MW		Fuel Type	Portfolio
10		2,997	Coal/Oil		46
10		2,277	Natural Gas		35
3		1,166	Water		18
2		78	Wind		1
25		6,518			100

In addition, PG&E NEG has seven facilities totaling 5,430 MW in construction and controls, through various arrangements, 581 MW in operation and 2,313 MW in construction, with a total owned and controlled generating capacity in operation or construction of 14,842 MW. PG&E NEG may sell selected operating assets in order to raise cash and provide equity to maintain its credit ratings while supplementing funding of its current construction projects. Any potential sales will likely involve plants or projects that diversify market risk, reduce future capital expenditures and/or reduce equipment commitments. PG&E NEG also has approximately 6,000 MW of natural gas-fired projects in various stages of development.

PG&E NEG engages in the marketing and trading of electric energy, capacity and ancillary services, fuel and fuel services such as pipeline transportation and storage, emission credits and other related products through over-the-counter and futures markets across North America. PG&E NEG’s marketing and trading team manages the supply of fuel for, and the sale of electric output from, its owned and controlled generating facilities and other trading positions. PG&E NEG also evaluates and implements structured transactions including management of third party energy assets, tolling arrangements, management of the requirements of aggregated customer load through full requirement contracts, restructured independent power project contracts and purchase and sale of transportation, storage and transmission rights through auctions and over-the-counter markets.

PG&E NEG uses financial instruments such as futures, options, swaps, exchange for physical, contracts for differences, and other derivatives to provide flexible pricing to its customers and suppliers and to manage its purchase and sale commitments, including those related to its owned and controlled generating facilities, gas pipelines and storage facilities. PG&E NEG also uses derivative financial instruments to reduce its exposure to the volatility of market prices and to hedge weather, interest rate and currency volatility.

Subsequent to the issuance of PG&E NEG’s condensed consolidated financial statements for the three month period ended March 31, 2001 included in its registration statement on Form S-4 filed with the Securities and Exchange Commission on July 27, 2001 and amended on August 21, 2001, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2001. A summary of the significant effects of the revisions to the Consolidated Statements of Operations and Consolidated Statements of Cash Flows is described more fully in Note 1 of the Notes to the Consolidated Financial Statements.

STATE OF INDUSTRY

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

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

events, many of which were consequences of the California energy crisis and the Enron bankruptcy, have increased uncertainty in the energy sector.

Conditions in the national energy markets will constrain PG&E NEG’s near-term growth. The U.S. economy has slowed significantly in the last year, and the timing for a recovery is uncertain. A lower level of economic activity may result in a decline in energy consumption and new electric supply additions begun during more robust economic conditions are beginning to commence operation. The combination of decreased consumption and increased supply may result in excess supply and declining operating margins for electric generators. Furthermore, these same factors may result in lower price volatility for energy products, potentially reducing profits from energy trading activities.

In response to these market changes, PG&E NEG may defer, cancel, sell, joint venture or otherwise dispose of some or all of PG&E NEG’s projects in development and the equipment associated with those projects.

PG&E NEG maintains an insurance program including coverage for power plant construction and operating risks. Recent events have adversely affected the insurance industry generally and the machinery and equipment segment in particular. This effect is especially acute for insurance covering unproven new technology turbines, including many of those PG&E NEG have in construction. As a result, PG&E NEG expects that its insurance coverages will be at lower levels than PG&E NEG has historically procured, certain coverages (for example, terrorism insurance) will no longer be available on commercially reasonable terms, deductibles will increase in size and premiums will be significantly higher.

LIQUIDITY AND FINANCIAL RESOURCES

The PG&E Energy and PG&E Pipeline business segments require substantial amounts of liquidity and capital resources to support construction, working capital, and counterparty credit requirements. PG&E NEG’s strategy is to finance PG&E NEG operations using a combination of funds from operations, equity, long-term debt (secured directly by those assets without recourse to other entities), long-term corporate borrowings in the capital markets, and short and medium term bank facilities that provide working capital, letters of credit and other liquidity needs. As of March 31, 2002, PG&E NEG had $691 million in cash and approximately $700 million available in unused credit lines.

Operating Activities

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

During the three months ended March 31, 2002, PG&E NEG generated net cash from operations of $84 million compared to net cash used in operations of $192 million for the same period in 2001, or an increase of $276 million. Increases in net income including adjustments to reconcile net income to net cash provided in operations activities, improved operating cash flow by $36 million period to period. The increase from period to period was primarily due to net price risk management activities, timing of deferred income tax, and increased non cash depreciation and amortization offsetting a lower net income. Cash flow from operations was also improved due to the net effect of changes in operating assets and liabilities of $240 million period to period. The net effect of changes in operating assets and liabilities was a use of operating cash for the three months ended March 31, 2001 of $189 million driven primarily by an increase in margin deposits relating to trading activities; whereas the net effect of changes in

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

operating assets and liabilities provided operating cash for the three months ended March 31, 2002 of $51 million and was primarily due to reduced margin level requirements and increased option premiums.

Investing Activities

PG&E NEG’s cash outflows from investing activities are primarily attributable to capital expenditures on generating and pipeline assets in construction and advanced development and turbine prepayments. During the three months ended March 31, 2002, PG&E NEG used net cash of $377 million in investing activities compared to $265 million for the same period in 2001, or an increase of $112 million. Construction expenditures were $335 million and $123 million for the three month periods March 31, 2002 and 2001, respectively. Advanced development and turbine prepayments were $5 million and $90 million for the three month periods March 31, 2002 and 2001, respectively. Other net expenditures were $37 million and $52 million for the three months ended March 31, 2002 and 2001, respectively. To date, PG&E NEG has made a number of commitments associated with the planned growth of owned and controlled generating facilities and pipelines. These include commitments for projects under construction, commitments for the acquisition and maintenance of equipment needed for the projects under development, payment commitments for tolling arrangements, and forward sale and purchase commitments associated with PG&E NEG’s energy marketing and trading activities.

Generating Projects in Construction—PG&E NEG currently owns, controls, or will own the output of ten generating facilities under construction. The following projects are consolidated by PG&E NEG: Lake Road, La Paloma, Athens, Plains End, Harquahala, and Covert. The table below outlines the expected dates that these will be completed.

		Percentage			Projected
Projects	Location	Completion			In-Service Dates
Athens	New York		34	%	3rd Quarter, 2003
Covert	Michigan		25	%	3rd Quarter, 2003
Harquahala	Arizona		24	%	2nd Quarter, 2003
Lake Road	Connecticut		99	%	2nd Quarter, 2002
La Paloma	California		96	%	4th Quarter, 2002
Plains End	Colorado		95	%	2nd Quarter, 2002

Additionally, PG&E NEG will control the output of the following projects: Southaven, Caledonia, Liberty Electric and a portion of Otay Mesa. Calpine Corporation (Calpine), the owner of the Otay Mesa project, has informed PG&E NEG that Otay Mesa is under construction.

A local intervenor group has contested in federal court the issuance of a U.S. Army Corps of Engineers (ACOE) permit for the Athens facility alleging, among other things, that the ACOE violated the National Environmental Policy Act. The intervenor group sought preliminary and permanent injunctive relief. The court denied the preliminary relief and the intervenor group has appealed.

PG&E NEG has executed construction contracts for its Smithland and Cannelton projects for up to 163 MW at two hydroelectric facilities on the Ohio River in Kentucky. PG&E NEG had commenced construction of the first 16

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

MW of turbines for the Smithland project, but has suspended construction. The ACOE reconsidered the permit it issued in light of recently stated seismic requirements and has initially determined that the design of the first hydroelectric facility does not meet such requirements given the condition of the dam where the facility is to be located. PG&E NEG disagrees with these findings and believes that even if the ACOE maintains its position, certain engineering and/or construction modifications will remedy any deficiency. In the event that PG&E NEG is unable to proceed with this facility, PG&E NEG will be compelled to either relocate the facility to a different dam at a cost yet to be determined or terminate the contract for the procurement and construction of the facility resulting in a termination payment to the contractor of approximately $15 million.

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

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

North Baja and the California State Lands Commission, along with Intergen Services, Inc. and Sempra Energy, are defendants in an action brought by the County of Imperial and the City of El Centro alleging that the environmental impact report prepared for the North Baja pipeline in California failed to address environmental justice issues as required by the California Environmental Quality Act (CEQA). The claim seeks an injunction restraining construction of the pipeline. Separately, the County of Imperial is contesting North Baja’s exercise of its eminent domain powers in obtaining property owned by the County of Imperial. PG&E NEG intends to vigorously defend the lawsuit and continue to pursue North Baja’s eminent domain rights. However, an adverse result in either contest could delay completion of the pipeline.

Generating Projects in Development—PG&E NEG has reviewed its growth plans for its electric generating business in light of circumstances presented by recent changes in energy and equity markets as well as the slowdown of the U.S. economy. Further, energy prices and price-earnings multiples for competitive energy companies have significantly declined, thereby constraining access to equity funds at acceptable terms to PG&E NEG. In response to these market changes, PG&E NEG continues to assess and modify its growth plans for ownership and control of electric generating facilities to manage its future capital and equity requirements. As a result, based on PG&E NEG’s view of the regional energy markets, PG&E NEG expects to delay, swap or sell generation development projects that are currently not under construction and associated commitments to take delivery of turbines. Since management’s review of its growth plans for ownership and control of electric generating facilities is ongoing, it is not practical to provide new projections of the total capacity that PG&E NEG will own or control.

Turbine Purchase Commitments—To support PG&E NEG’s development program, PG&E NEG has contractual commitments and options for combustion turbines and related equipment representing approximately 14,000 MW of

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

net generating capacity. In connection with PG&E NEG’s current revised development plans, PG&E NEG has restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap or sale of generation projects in development. If PG&E NEG determines to further defer or cancel a project, PG&E NEG may create a mismatch between equipment delivery schedules and its development plans. If equipment delivery schedules cannot be adjusted, PG&E NEG may be compelled to choose between paying for equipment which PG&E NEG would have to store for future use or terminating the commitments to purchase equipment. If PG&E NEG decides to terminate such commitments to purchase, PG&E NEG would incur costs to the equipment vendors consisting of amounts shown as assets on its balance sheet plus all additional cash payments, if any, due upon termination (Termination Costs).

Generally, each of PG&E NEG’s equipment supply contracts allows PG&E NEG to cancel any or all of its commitments to purchase the equipment for a predefined cost. To date, PG&E NEG has not cancelled any of its equipment commitments or options. PG&E NEG continues to work with its vendors to defer payments, delay increases of termination fees and revise equipment delivery dates. PG&E NEG has good relationships with its vendors and has, to date, been largely successful in these efforts. However, PG&E NEG cannot provide assurance that it will continue to be able to modify these agreements to minimize PG&E NEG Termination Costs and match equipment deliveries with its evolving development plans. PG&E NEG’s exposure for these Termination Costs gradually increases over time and is approximately $250 million as of March 31, 2002. PG&E NEG’s cash exposure for Termination Costs would be offset by amounts expended for the equipment through the date of termination. PG&E NEG’s estimates of its exposure for Termination Costs are, in part, based upon current contractual arrangements.

Financing Activities

PG&E NEG’s cash outflows from financing activities were primarily attributable to increases in borrowings under PG&E NEG’s credit facilities relating to the continuing completion of PG&E NEG’s construction facilities and borrowings under construction financing. For the three months ended March 31, 2002 and 2001, PG&E NEG provided net cash flows from financing activities of $259 million and $166 million, respectively. This increase is primarily related to the construction funding needed for the Athens, Lake Road, La Paloma, Covert and Harquahala projects.

Credit Ratings and Rating Triggers —The credit ratings as of March 31, 2002 of the various debt instruments of PG&E NEG are as follows:

	Standard		Moody's
	& Poor's		Investors Service
Senior Unsecured Notes Due 2011 (NEG)	BBB		Baa2
Senior Unsecured Notes Due 2005 (GTN)		A-	Baa1
Senior Unsecured Debentures Due 2025 (GTN)		A-	Baa1
Medium Term Notes (nonrecourse) GTN		A-	Baa1
Outstanding Credit Facilities	Various		Various
Term Loan – GenHoldings I, LLC	BBB-		Baa3
Mortgage Loans & Other	Not Rated		Not Rated

Some of PG&E NEG’s financial arrangements require PG&E NEG or an affiliate to maintain certain ratings from S&P and/or Moody’s Investors Services, Inc. (Moody’s). These provisions are referred to as “ratings triggers”. While the specifics of the ratings that are required to be maintained, the remedy, the cure period in the event of a downgrade, and the result if certain actions are not taken as a result of the downgrade differ with each agreement, these provisions generally require PG&E NEG to provide cash, a letter of credit, or other acceptable replacement security, as collateral.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

The most significant ratings triggers include the following:

• PG&E NEG’s $609 million equity commitments for Lake Road and La Paloma require PG&E NEG to maintain BBB- or Baa3 ratings from either S&P or Moody’s. These ratings triggers provide for a 30 day period to post replacement security after which lenders could request equity funding within 5 days. Lenders are currently evaluating a proposed amendment to remove these ratings triggers.

• Lenders have approved the removal of ratings triggers from PG&E NEG’s guarantee backing the $280 million equipment revolving credit facility, subject to lender approval of the removal of ratings triggers in the Lake Road and La Paloma financings. Until this approval is effective, PG&E NEG is required to maintain a BBB- or Baa3 rating from either S&P or Moody’s, respectively. In the event of a downgrade, PG&E NEG has 30 days to post acceptable replacement security, or, following receipt of a payment demand from the lenders, PG&E NEG has 5 days to repay all outstanding borrowings under the facility.

On April 17, 2002, Moody’s changed the rating outlook on the debt securities of PG&E NEG to negative from stable reflecting the growing reliance on less predictable cash flows coupled with the weak marketplace for merchant generation. This does not change the above tables.

Ratings triggers have been removed from PG&E NEG’s guarantee backing its $701 million equity commitment for the GenHoldings I, LLC portfolio financing.

In each case in which triggers have been or will be removed from PG&E NEG’s financial arrangements, the triggers are replaced by deferred financial standards.

Guarantees—PG&E NEG has provided guarantees supporting its tolling agreements, agreements related to energy trading and other agreements relating to the generating assets. These guarantees are discussed in Note 5 to the Consolidated Financial Statements.

RISK MANAGEMENT ACTIVITIES

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

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

Fair values of trading contracts at January 1, 2002	$	33
Net gain on contracts settled during the period		(45	)
Fair value of new trading contracts when entered into		—
Changes in fair values attributable to changes in valuation techniques and assumptions		—
Other changes in fair values		43
Fair values of trading contracts outstanding at March 31, 2002		31

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

Fair value of non-trading contracts		(28	)
Net price risk management assets at March 31, 2002	$	3

PG&E NEG estimated the gross mark-to-market value of its trading contracts as of March 31, 2002, using the mid-point of quoted bid and ask prices, where available, and other valuation techniques when market data was not available (e.g. illiquid markets or products). When market data is not available, PG&E NEG utilizes alternative pricing methodologies, including, but not limited to, third party pricing curves, the extrapolation of forward pricing curves using historically reported data or interpolating between existing data points.

The following table shows the mark-to market value of PG&E NEG’s trading contracts after deduction of time value, credit, model and other reserves necessary to determine fair value (in millions).

				Fair Value of Trading Contracts at March 31
										Maturity
	Maturity			Maturity			Maturity			in Excess		Total
	Less Than			One-Three			Four-Five			of Five		Fair
Source of Prices* used in Estimating Fair Value	One Year			Years			Years			Years		Value
Actively quoted	$	92		$	14		$	(14	)	$	1		$	93
External sources, including inflation adjustments		—			—			(11	)		29			18
Based on models and other valuation methods		(43	)		(42	)		(1	)		6			(80	)
Total Mark to Market	$	49		$	(28	)	$	(26	)	$	36		$	31

* 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, as these positions may be changed by new transactions in the trading portfolio at any time in response to changing market conditions, market liquidity, and PG&E NEG’s risk management portfolio needs and strategies.

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

Commodity Price Risk—Commodity price risk is the risk that changes in market prices of a commodity for physical delivery will adversely affect earnings and cash flows. PG&E NEG is exposed to commodity price risk for its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, in addition to various merchant plants currently in development and construction. PG&E NEG manages such risks using a risk management program that primarily includes the buying and selling of fixed-price commodity commitments to lock in future cash flows of forecasted generation. PG&E NEG is also exposed to commodity price risk for net open positions within the trading portfolio due to the assessment of and response to changing market conditions.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

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

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

The following table illustrates the daily value-at-risk exposure for commodity price risk for March 31, 2002 (in millions).

Trading	8
Non-Trading(1)	19

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

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.

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

PG&E NEG uses the following interest rate instruments to manage its interest rate exposure: interest rate swaps, interest rate caps, floors, or collars, swaptions, or interest rate forward and futures contracts. Interest rate risk sensitivity analysis is used to measure interest rate price risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. As of March 31, 2002, if interest rates change by 1 percent for all variable rate debt at PG&E NEG, the change would be immaterial, based on variable rate debt and derivatives and other interest rate sensitive instruments outstanding.

Foreign Currency Risk—Foreign currency risk is the risk of changes in value of pending financial obligations in foreign currencies that could occur prior to the settlement of the obligation due to a change in the value of that foreign currency in relation to the U.S. dollar. PG&E NEG is exposed to foreign currency risk associated with foreign currency exchange variations related to Canadian-denominated purchase and swap agreements. In addition, PG&E NEG has

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

translation exposure resulting from the need to translate Canadian-denominated financial statements of its affiliate PG&E Energy Trading, Canada Corporation into U.S. dollars for PG&E NEG Consolidated Financial Statements. PG&E NEG uses forwards, swaps, and options to hedge foreign currency exposure.

PG&E NEG uses sensitivity analysis to measure its foreign currency exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at March 31, 2002, a 10 percent devaluation of the Canadian dollar would be immaterial to PG&E NEG’s Consolidated Financial Statements.

Credit Risk—Credit risk is the risk of loss that PG&E NEG would incur if counterparties fail to perform their contractual obligations. PG&E NEG conducts business primarily with customers in the energy industry, and this concentration of counterparties may impact the overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory, or other conditions. PG&E NEG manages credit risk pursuant to its Risk Management Policies, which provide processes by which counterparties are assigned credit limits in advance of entering into significant exposure. These procedures include an evaluation of a potential counterparty’s financial condition, net worth, credit rating, and other credit criteria as deemed appropriate and are performed at least annually. Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E NEG takes immediate action to reduce exposure and/or obtain additional collateral. Further, PG&E NEG relies heavily on master agreements that allow for the netting of positive and negative exposures associated with a counterparty, under certain circumstances.

As of March 31, 2002, PG&E NEG’s only customer greater than 10 percent of its total credit exposure was the State of California Department of Water Resources, which represented 13 percent of PG&E NEG’s credit exposure.

The schedule below summarizes the exposure to counterparties that are in a net asset position, with the exception of written options and exchange-traded futures (the exchange provides for contract settlement on a daily basis), as of March 31, 2002(in millions):

Gross	Credit
Exposure(1)	Collateral(2)		Net Exposure(2)
$786		$90		$696

(1)	Gross credit exposure equals mark-to-market value plus net (payables) receivables where netting is allowed.
(2)	Net exposure is the gross exposure minus credit collateral (cash deposits and letters of credit). Amounts are not adjusted for probability of default.

The majority of counterparties to which PG&E NEG is exposed are considered to be of investment grade, determined using publicly available information including an S&P’s rating of at least BBB-. PG&E NEG’s net credit exposure to below investment grade entities, consisting principally of Southern California Edison, DWR, and Pacific Gas and Electric Company, aggregates to approximately $230 million or 33 percent. PG&E NEG’s concentration of credit exposure is to counterparties that conduct business primarily in North America.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

RESULTS OF OPERATIONS
(in millions)

	Integrated Energy
	and Marketing		Interstate Pipeline		Other and
	Activities		Operations		Eliminations (1)			TOTAL
For the three months ended March 31, 2002
Total operating revenues	$	2,293	$	59	$	(4	)		2,348
Total operating expenses		2,256		26		5			2,287
Total operating income		37		33		(9	)		61
Interest income									16
Interest expense									33
Other income (expense), net									3
Income before income tax									47
Income taxes provision									10
Net income									37
Net cash provided by operating activities									84
Net cash used in investing activities									(377	)
Net cash provided by financing activities									259
EBITDA (2)	$	71	$	46	$	(5	)	$	112
For the three months ended March 31, 2001 (as revised, see Note 1)
Total operating revenues	$	4,150	$	65	$	(9	)	$	4,206
Total operating expenses		4,097		25		(1	)		4,121
Total operating income		53		40		(8	)		85
Interest income									25
Interest expense									27
Other income (expense), net									5
Income before income tax									88
Income taxes provision									34
Net Income								$	54
Net cash used in operating activities									(192	)
Net cash used in investing activities									(265	)
Net cash provided by financing activities									166
EBITDA (2)	$	84	$	51	$	(7	)	$	128
Footnotes

(1)

All inter-segment transactions are eliminated.

(2)

EBITDA is defined as income before provision for income taxes, interest expense, interest income, depreciation, and amortization. EBITDA is not intended to represent cash flows from operations and should not be considered as an alternative to net income or as an indicator of PG&E NEG’s operating performance or to cash flows as a measure of liquidity. Refer to the Statement of Cash Flows for the U.S. GAAP basis cash flows. PG&E NEG believes that EBITDA is a standard measure commonly reported and widely used by analysts, investors, and other interested parties. However, EBITDA as presented herein may not be comparable to similarly titled measures reported by other companies.

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

Three Months Ended March 31, 2002 as Compared to Three Months Ended March 31, 2001

Overall Results:PG&E NEG’s net income was $37 million for the three months ended March 31, 2002, a decrease of $17 million from the three months ended March 31, 2001. PG&E NEG’s pre-tax operating income decreased $24 million mainly due to lower gross margins principally related to operations in New England, higher operations and maintenance costs due to the timing of major overhauls and higher depreciation due to the start-up and acquisitions of new plants in 2001. Offsetting these declines was an improvement in administrative and general costs primarily related to lower employee related expenses in the first quarter of 2002. Interest expense was higher due to the PG&E NEG $1 Billion Senior Notes which were issued in the second quarter of 2001. PG&E NEG’s effective tax rate was lower for the three months ended March 31, 2002 as compared to the same period last year mainly due to certain energy tax credits. The following highlights the principal changes in operating revenues and operating expenses.

Operating Revenues:PG&E NEG’s operating revenues were $2.348 billion in the three months ended March 31, 2002, a decrease of $1.858 billion from the three months ended March 31, 2001. These declines occurred primarily in the Integrated Energy and Marketing Activities segment. PG&E NEG’s wholesale energy trading business declines are primarily due to a decline in commodity prices and significantly compressed spark spreads in the first quarter in 2002 as compared to the same period last year. In addition, operating revenues declined in New England primarily due to lower energy prices and a lower fuel adjustment provision partially offset by hedges. Interstate Pipeline Operations operating revenues declined $6 million due to a decline in interruptible gas transportation revenue in the California and Pacific Northwest gas markets compared to the same period last year.

Operating Expenses:PG&E NEG’s operating expenses were $2.287 billion in the three month period ended March 31, 2002, a decrease of $1.834 billion from the same period in the prior year. These declines occurred primarily in the Integrated Energy and Marketing segment. The cost of commodity sales and fuel declined $1.847 billion in line with the declines in operating revenues within the wholesale energy trading business. Operations, maintenance and management costs increased $15 million in the first quarter of 2002 as compared to the same period last year principally due to the timing of major overhauls at generation facilities. Depreciation and amortization costs also increased $10 million in the period mainly due to the increase of new projects and acquisitions in 2001. Offsetting these increases in operating costs was a decline in administrative and general operating costs principally associated with lower employee related expense.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

In August 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” This Statement is effective for fiscal years beginning after June 15, 2002. SFAS No. 143 provides accounting requirements for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. Under the Statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing the carrying amount of the related long-lived asset. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful life of the related asset. PG&E NEG is currently evaluating the impact of SFAS No. 143 on its consolidated financial statements.

In addition to its derivatives designated as cash flow hedges 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), PG&E NEG also has derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and

33

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

thus are not reflected on the balance sheet at fair value. Another attribute that a contract must have to qualify for the normal purchases and sales exemption is that the pricing must be deemed to be clearly and closely related to the asset to be delivered under the contract. In June 2001 (as amended in October 2001 and December 2001), the FASB approved an interpretation issued by the Derivatives Implementation Group (DIG), DIG C15, that changed the definition of normal purchases and sales for certain power contracts. Implementation of this interpretation will result in several contracts’ failure to continue qualifying for the normal purchases and sales exemption under DIG C15, resulting in these contracts being marked-to-market through earnings. The FASB has also approved another DIG interpretation, DIG C16, that disallows normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. PG&E NEG determined that certain of its fuel contracts no longer qualify for normal purchases and sales treatment under DIG C16, and must be marked-to-market through earnings. PG&E NEG must implement both of these interpretations beginning in April 2002. PG&E NEG is in the process of completing its evaluation and valuation of those contracts that are disqualified from normal purchases and sales treatment by application of DIG C15 and DIG C16. Based on its preliminary analysis, PG&E NEG estimates that certain of the contracts have pre-tax mark-to-market losses totaling approximately $170 million and certain of the contracts have pre-tax mark-to-market gains totaling approximately $250 million. Upon concluding its final evaluation and valuation of the contracts impacted by DIG C15 and DIG C16, PG&E NEG will record the net after-tax impact as a cumulative effect of a change in accounting principle at April 1, 2002.

Any cumulative impact from the accounting change reflected in the second quarter will not impact the timing and amount of cash flows associated with the affected contracts. The cumulative effect will, however, impact the timing and extent of future operating results. The cumulative effect will reflect the mark-to-market value of the contracts immediately. In addition, future earnings will primarily reflect prospective changes in the market value of these contracts

CRITICAL ACCOUNTING POLICIES

Effective 2001, PG&E NEG adopted SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 which required all financial instruments to be recognized in the financial statements at market value. See further discussion in Price Risk Management Activities and Note 3 to the Consolidated Financial Statement. PG&E NEG accounts for its energy trading activities in accordance with EITF 98-10 and SFAS No. 133 which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting. EITF 98-10 also allows two methods of recognizing energy trading contracts in the income statement. The “gross” method provides that the contracts are recognized at their full value in revenue and expenses. The other method is the “net” method in which revenues and expenses are netted and only the trading margin (or sometimes trading loss) is reflected in revenues. PG&E NEG uses the gross method for those energy trading contracts for which PG&E NEG has a choice.

PG&E NEG also has derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. These derivatives are exempt from the requirements of SFAS No. 133, under the normal purchase and sales exception, and are not reflected on the balance sheet at fair value. See further discussion in “Accounting Pronouncements Issued But Not Yet Adopted” above.

PG&E NEG applies SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation” to PG&E GTN’s regulated natural gas transportation business. This standard allows a cost to be capitalized, that otherwise would be charged to expense if it is probable that the cost is recoverable through regulated rates. This standard also allows a regulator to create a liability that is recognized in PG&E GTN’s financial statements.

ENVIRONMENTAL AND LEGAL MATTERS

PG&E NEG are subject to laws and regulations established to both maintain and improve the quality of the environment. Where PG&E NEG properties contain hazardous substances, these laws and regulations require

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MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—(Continued)

PG&E NEG to remove those substances or remedy effects on the environment. Also, in the normal course of business, PG&E NEG are named as parties in a number of claims and lawsuits. See Note 5 of the Notes to the Consolidated Financial Statements for further discussion of environmental matters and significant pending legal matters.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

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

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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS

California Energy Trading Litigation—For information regarding this matter, please see PG&E NEG’s Annual Report on Form 10-K for the year ended December 31, 2001.

Brayton Point—On March 27, 2002, Rhode Island Attorney General Sheldon Whitehouse, notified USGenNE, of his belief that the company’s Brayton Point Station “is in violation of applicable statutory and regulatory provisions governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into Mt. 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. The notice purportedly was provided pursuant to section 7A of chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point Station is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. PG&E NEG is currently awaiting the issuance of a draft Clean Water Act NPDES permit renewal from the EPA. On March 27th......Management is unable to predict whether the ultimate outcome of this matter will have a material adverse affect on PG&E NEG's financial condition or results of operations.

Natural Gas Royalties Litigation—For information regarding this matter, please see PG&E NEG’s Annual Report on Form 10-K for the year ended December 31, 2001.

North Baja Pipeline Litigation—North Baja and the California State Lands Commission are defendants in an action brought by the County of Imperial and the City of El Centro alleging that the environmental impact report prepared for the North Baja pipeline by the California State Lands Commission fails to meet the requirements of the California Environmental Quality Act (CEQA). County of Imperial and City of El Centro v. California State Lands Commission (North Baja Pipeline LLC, Intergen Services, Inc. and Sempra Energy, Real Parties in Interest), Sacramento County (California) Superior Court Case No. 02CS00327 (“North Baja Pipeline Litigation”). The action contains eleven causes of action, all of which are alleged violations of CEQA. The first cause of action alleges that the State Lands Commission in preparing the environmental impact report, failed to address environmental justice issues. The remaining causes of action all challenge the environment impact report on various grounds. Most of these causes of action are based on a claim and theory that the environmental impact report was required to evaluate and mitigate, as part of the California pipeline project, potential air emissions from power plants located in Mexico which (in addition to plants in San Diego County) will be served by the pipeline. Plaintiffs prayer for relief further seeks to enjoin construction of the pipeline, although to date no injunction has been sought. Separately, on March 20, 2002 North Baja filed a complaint seeking to condemn certain property owned by County of Imperial under which the pipeline will be constructed. North Baja Pipeline v. 4.31 Acres in Imperial County California, et al. Case No. 02 CV 00526 BTM (Southern District Court of California). On April 4, 2002 North Baja filed an ex parte application for immediate possession of the property and deposited with the court the estimated value of the property ($162,500). Construction of the pipeline is proceeding notwithstanding this litigation. PG&E NEG believes that the outcome of this matter will not have a material adverse affect on its financial condition or results of operations.

Athens Litigation—PG&E NEG has been granted a permit for its Athens project by the U.S. Army Corps of Engineers (ACOE) which, among other things, authorized it to construct the water intake structure of the Athens facility. A local intervenor group contested the issuance of the permit. The ACOE rejected the group’s challenges and issued the permit. The intervenor group thereupon filed a lawsuit in federal district court (Pogliani, et al v. United States Army Corps of Engineers, Civil Action No. 01-CV-0951) seeking preliminary and injunctive relief. The court declined to grant the preliminary injunctive relief. The intervenor group is now appealing this decision to the U.S. Court of Appeals for the Second Circuit. PG&E NEG believes that the outcome of this matter will not have a material adverse effect on its financial condition or results of operations.

California Attorney General Complaint—On March 20, 2002 the California Attorney General filed a complaint at FERC against ET-Power and other named and unnamed public utility sellers of energy and ancillary services. State of Californiaex rel.Bill Lockyer, Docket No. EL02-71-000. The Attorney General alleges that wholesale sellers of energy to the California ISO, PX and CDWR failed to file their rates in accordance with the requirements of Section 205 of the Federal Power Act. Specifically, the California Attorney General claims that FERC has not been able to determine whether the rates charged by such sellers are just and reasonable; that FERC’s reporting requirements are not sufficient to allow the Commission the information necessary to make this determination and that even if FERC’s policies and procedures did comply with Section 205 of the Federal Power Act, the wholesale sellers failed to comply with its quarterly reporting requirements. As a result, the California Attorney General requests that: (1) sellers should be directed to comply, on a prospective basis, with the requirements of Section 205 of the Federal

37

Power Act; (2) sellers should be required to provide transaction-specific information regarding their short-terms sales to the ISO, PX and CDWR for the years 2000 and 2001 to the FERC; (3) if rates were charged that were not just and reasonable, refunds should be ordered; (4) the Commission should declare that market-based rates are not subject to the filed rate doctrine; and (5) the Commission should institute proceedings to determine whether any further relief would be appropriate. PG&E-NEG believes that the outcome of this matter will no have a material adverse affect on its financial condition or results of operations.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits:

*10.1 Description of Short Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2002 (incorporated by reference to PG&E Corporation’s Annual Report on Form 10-K for the year ended December 31, 2001, Ex. 10.25)

*10.3 PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001 (incorporated by reference to PG&E Corporation’s Annual Report on Form 10-K for the year ended December 31,2001, Ex. 10.4)

*10.2 PG&E Corporation Officer Severance Policy, dated December 19, 2001(incorporated by reference to PG&E Corporation’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, Ex. 10.2)

*Management contract or compensatory plan or arrangement required to be filed as an exhibit.

(b) The following Current Reports on Form 8-K were filed during the first quarter of 2002 and through the date hereof:

1.	Current Report on Form 8-K dated February 28, 2002
2.	Current Report on Form 8-K dated April 19, 2002

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SIGNATURES

     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.

			PG&E NATIONAL ENERGY GROUP, INC. (Registrant)
Dated:	May 1, 2002	By:	/s/   Thomas G. Boren
			Thomas G. Boren
			President and Chief Executive Officer
Dated:	May 1, 2002	By:	/s/    Thomas E. Legro
			Thomas E. Legro
			Vice President, Chief Accounting Officer
			and Controller

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