PG&E NATIONAL ENERGY GROUP INC - 10-Q 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 June 30, 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 (State or Other Jurisdiction of Incorporation or Organization)		7600 Wisconsin Avenue (Mailing address: 7500 Old Georgetown Road) Bethesda, Maryland 20814 (301) 280-6800		94-3316236 (I.R.S. Employer Identification Number)

(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 June 30, 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 Electric Industry		9
		Note 3: Price Risk Management		10
		Note 4: Debt Financing		13
		Note 5: Commitments and Contingencies		13
		Note 6: Segment Information		19
		Note 7: Impairment of Project Development, Turbines, and Other Related Equipment Costs
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of			20
	Operations
		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
		New Accounting Policies		34
		Critical Accounting Policies		34
		Taxation Matters		34
		Environmental 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

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

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


			Three Months Ended						Six Months Ended
			June 30,						June 30,
							As revised						As revised
							see						see
							Note 1						Note 1

			2002			2001			2002			2001
OPERATING REVENUES
	Generation, transportation, and trading		$	3,055		$	2,730		$	5,385		$	6,910
	Equity in earnings of affiliates			5			23			23			49

		Total operating revenues		3,060			2,753			5,408			6,959

OPERATING EXPENSES
	Cost of commodity sales and fuel			2,845			2,387			4,932			6,321
	Operations, maintenance, and management			162			142			303			268
	Administrative and general			17			15			24			36
	Impairments and write-offs			265			—			265			—
	Depreciation and amortization			41			37			89			75
	Other operating expenses			10			47			14			49

		Total operating expenses		3,340			2,628			5,627			6,749

OPERATING INCOME (LOSS)				(280	)		125			(219	)		210
	Interest income			16			24			32			49
	Interest expense			(56	)		(31	)		(89	)		(58	)
	Other income (expense), net			(6	)		1			(3	)		6

INCOME (LOSS) BEFORE INCOME TAXES				(326	)		119			(279	)		207
	Income taxes provision (benefit)			(146	)		48			(136	)		82

NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE				(180	)		71			(143	)		125

CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE, net of applicable income tax benefit of $42 million				(61	)		—			(61	)		—

NET INCOME (LOSS)			$	(241	)	$	71		$	(204	)	$	125

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

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


				BALANCE AT

				June 30,			December 31,
				2002			2001

ASSETS
CURRENT ASSETS
	Cash and cash equivalents			$	766		$	725
	Restricted cash				252			141
	Accounts receivable:
		Trade, net of allowance for uncollectibles of $45 million and $43 million, respectively			1,207			1,031
		Related parties			37			40
	Other receivables				31			54
	Inventory				154			125
	Price risk management				508			381
	Prepaid expenses and other				391			141

			Total current assets		3,346			2,638

PROPERTY, PLANT AND EQUIPMENT
	Electric generating facilities				2,889			2,735
	Gas transmission assets				1,519			1,512
	Land				131			131
	Other				187			163
	Construction work in progress				2,508			2,100

		Total property, plant and equipment (at original cost)			7,234			6,641
	Accumulated depreciation				(959	)		(887	)

		Net property, plant and equipment			6,275			5,754

OTHER NONCURRENT ASSETS
	Long-term receivables				414			455
	Long-term receivables from PG&E Corporation				—			174
	Investments in unconsolidated affiliates				393			414
	Goodwill, net of accumulated amortization of $30 million				95			95
	Intangible assets, net of accumulated amortization of $22 million and $19 million, respectively				78			85
	Deferred financing costs, net of accumulated amortization of $18 million and $6 million, respectively				104			79
	Price risk management				574			302
	Other				143			333

		Total other noncurrent assets			1,801			1,937

TOTAL ASSETS				$	11,422		$	10,329

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


				BALANCE AT

				June 30,			December 31,
				2002			2001

LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY
CURRENT LIABILITIES
	Short-term borrowings			$	344		$	330
	Long-term debt, classified as current				48			48
	Obligations due Parent				209			309
	Accounts payable:
		Trade			1,110			957
		Related parties			40			41
	Accrued expenses				397			336
	Price risk management				548			277
	Out-of-market contractual obligations				95			116
	Other				281			97

			Total current liabilities		3,072			2,511

NONCURRENT LIABILITIES
	Long-term debt				4,016			3,374
	Deferred income taxes				537			681
	Price risk management				751			310
	Out-of-market contractual obligations				542			683
	Long-term advances from PG&E Corporation				118			118
	Other noncurrent liabilities and deferred credits				78			65

			Total noncurrent liabilities		6,042			5,231

MINORITY INTEREST					23			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				(814	)		(610	)
	Accumulated other comprehensive income (loss)				(45	)		33

			Total common stockholders’ equity		2,227			2,509

TOTAL LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY				$	11,422		$	10,329

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

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


				Six Months Ended
				June 30,

							As revised, see
							Note 1
				2002			2001

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income (loss)			$	(204	)	$	125
	Adjustments to reconcile net income to net cash provided by (used in) operating activities:
		Depreciation and amortization			89			75
		Deferred income taxes			(129	)		(72	)
		Price risk management assets and liabilities — net			67			(33	)
		Amortization of out-of-market contractual obligation			(88	)		(73	)
		Other deferred credits and noncurrent liabilities			12			(5	)
		Loss on impairment of assets			265			—
		Equity in earnings of affiliates			(23	)		(49	)
		Distributions from affiliates			25			38
		Cumulative effect of a change in accounting principle			61			—
	Net effect of changes in operating assets and liabilities:
		Restricted cash			(111	)		(66	)
		Accounts receivable—trade			(54)			1,290
		Inventories, prepaids and deposits			(67	)		60
		Accounts payable and accrued liabilities			155			(1,266	)
		Accounts payable—related parties – net			2			13
		Other, net			18			(3	)

			Net cash provided by operating activities		18			34

CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures				(937	)		(572	)
	Proceeds from sale leaseback				340			—
	Long-term prepayment on turbines				—			(136	)
	Other—net				67			35

			Net cash used in investing activities		(530	)		(673	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Net borrowings (repayment) under credit facilities				14			(74	)
	Repayment of obligations due related parties and affiliates				(100	)		—
	Long-term debt issued				938			396
	Notes issuance, net of discount and issuance costs				—			972
	Long-term debt matured, redeemed, or repurchased				(299	)		(592	)

			Net cash provided by financing activities		553			702

NET CHANGE IN CASH AND CASH EQUIVALENTS					41			63
CASH AND CASH EQUIVALENTS, AT January 1					725			738

CASH AND CASH EQUIVALENTS, AT June 30				$	766		$	801


SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
	Cash paid for:
		Interest paid		$	175		$	91
		Income taxes paid, (refunded) – net			8			—
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING:
	Reclassification of short-term parent receivable to long-term				—			203
	Reclassification of long-term parent receivable to short-term				99			—
	Non-cash impact of DIG C15 and DIG C16:
		Deferred income taxes			(43	)		—
		Out-of-market contractual obligation			(75	)		—
		Price risk management assets and liabilities — net			194			—
	Reclassification of demand notes payable to parent from short-term to long-term				—			118
	Long-term debt related to the purchase of Attala Generating Company				—			(40	)
	Change in other comprehensive (income) loss due to No. SFAS 133, net of deferred taxes				70			110
	Change in equity investment due to SFAS No. 133				2			(45	)
	Transfer of assets from long-term prepaid to construction in progress				—			(535	)

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

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 (collectively, 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 Gen); 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) and North Baja Pipeline, LLC (NBP). 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 these investments in affiliated entities, which include corporations, limited liability companies and partnerships. Under this method, PG&E NEG’s share of equity income or losses of these entities is reflected as equity in earnings of affiliates. 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 Annual Report on 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.

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				Six Months Ended
		June 30, 2001				June 30, 2001

		As				As
		Previously		As		Previously			As
		Reported		Revised		Reported			Revised

CONSOLIDATED STATEMENTS OF OPERATIONS
Generation, transportation, and trading		$	2,733	$	2,730	$	6,915		$	6,910
	Total operating revenues		2,756		2,753		6,964			6,959
Operations, maintenance, and management			145		142		273			268
	Total operating expenses		2,631		2,628		6,753			6,749
CONSOLIDATED STATEMENTS OF CASH FLOWS
Capital expenditures						$	(288	)	$	(572	)
Long-term prepayment on turbines							(268	)		(136	)
Long-term debt issued							259			396

Stock-Based Compensation

PG&E NEG accounts for stock-based compensation associated with PG&E Corporation’s stock option plans using the intrinsic value method in accordance with the provision of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” as allowed by Statement of Financial Accounting Standards (SFAS) No. 123, “Accounting for Stock-Based Compensation.” Under the intrinsic value method, PG&E NEG does not recognize any compensation expense, as the exercise price of all stock options is equal to the fair market value at the time the options are granted. Had compensation expense been recognized using the fair value-based method under SFAS No. 123, PG&E NEG’s pro-forma consolidated income (loss) would have been as follows (in millions):


	Three months ended					Six months ended
	June 30,					June 30,
	2002			2001		2002			2001

Net Income (loss):
As reported	$	(241	)	$	71	$	(204	)	$	125
Pro-forma		(243	)		69		(208	)		122

Comprehensive Income (Loss)

PG&E NEG’s comprehensive income (loss) consists principally of changes in the market value of certain cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (in millions):


	2002			2001

Three months ended June 30
Net income (loss)	$	(241	)	$	71
Net gain (loss) in other comprehensive income (OCI) from current period hedging transactions and price changes in accordance with SFAS No. 133		(9	)		186
Net reclassification from OCI to earnings		—			10

Comprehensive income (loss)	$	(250	)	$	267

Six months ended June 30
Net income (loss)	$	(204	)	$	125
Cumulative effect of adoption of SFAS No. 133		—			(333	)
Net gain (loss) in OCI from current period hedging transactions and price changes in accordance with SFAS No. 133		(84	)		156
Net reclassification from OCI to earnings		5			112

Comprehensive income (loss)	$	(283	)	$	60

Significant Accounting Policies

Except as disclosed below, PG&E NEG is following the same accounting principles discussed in the 2001 Annual Report on Form 10K.

Adoption of New Accounting Policies

Accounting for Goodwill and Other Intangible Assets: 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. Upon implementation of this Statement, the transition impairment test for goodwill was performed as of January 1, 2002, and no impairment loss was recorded. Goodwill amortization expense for the three and six months ended June 30, 2001 was $1 million and $2 million, respectively. 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. The schedule below summarizes the amount of intangible assets by major classes (in millions):


	Balance at

	June 30, 2002				December 31, 2001

	Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amount		Amortization		Amount		Amortization

Service agreements	$	33	$	6	$	33	$	6
Power sale agreements		41		9		44		8
Other agreements		26		7		27		5

Total	$	100	$	22	$	104	$	19

Amortization expense on intangible assets for the three and six months ended June 30, 2002 was $2 million and $3 million, respectively, compared to $1 million and $2 million for the same periods in 2001. These amounts do not include amortization expense related to intangibles for certain power sale agreements, which are recorded against the related revenue or expense.

The following schedule shows the estimated amortization expense for intangible assets for the full years 2002 through 2006 (in millions):


2002	2003		2004		2005		2006

$6	$	6	$	6	$	6	$	6

Accounting for Impairment or Disposal of Long-Lived Assets: 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 its fundamental provision for recognizing and measuring impairment of long-lived assets to be held and used. This Standard also requires that all long-lived assets to be disposed of by sale are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should cease to be recorded on such assets. SFAS 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, superseding previous guidance for discontinued operations of business segments. The adoption of the Statement did not have any impact on the Consolidated Financial Statements of PG&E NEG.

Changes to Accounting for Certain Derivative Contracts : On April 1, 2002, PG&E NEG implemented two interpretations issued by the Financial Accounting Standard Board’s (FASB) Derivatives Implementation Group (DIG). DIG Issues C15 and C16 changed the definition of normal purchases and sales included in 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” and ongoing interpretation of the FASB’s DIG (collectively, SFAS No. 133). Previously, certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business were exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception, and thus were not marked to market and reflected on the balance sheet like other derivatives. Instead, these contracts were recorded on an accrual basis.

DIG C15 changed the definition of normal purchases and sales for certain power contracts. DIG C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. PG&E NEG determined that five of its derivative commodity contracts for the physical delivery of power and purchase of fuel no longer qualified for normal purchases and sales treatment under these interpretations. Beginning April 1, 2002, these five contracts were required to be recorded on the balance sheet at fair value and marked to market through earnings. Three of the contracts had positive market values and resulted in pre-tax income of $125 million. The remaining two contracts had negative market values that resulted in a pre-tax charge of $127 million. The cumulative effects of implementation of these accounting changes at April 1, 2002, resulted in PG&E NEG recording price risk management assets of $37 million, price risk management liabilities of $255 million, a reduction of out-of-market obligations of $129 million reclassified to net price risk management liabilities and an increase in investments in unconsolidated affiliates of $87 million.

One of the contracts with a positive market value included above is for a power sales contract at a partnership in which PG&E NEG has a 50% ownership interest. PG&E NEG reflects its investment in this partnership on an equity basis (Investments in Unconsolidated Affiliates). Upon adoption of C15 and C16, PG&E NEG recognized its equity share of the gain from the cumulative change in accounting method and correspondingly increased the book value of its equity investment in the partnership. However, the future net cash flows from the partnership do not support the increased equity investment balance. Therefore, PG&E NEG has recognized an impairment charge of $101 million to reduce its equity-method investment to fair value. The cumulative effect of the change in accounting principle for DIG C15 and C16 was a net charge of $61 million, after-tax, and included the recognition of the fair market value of the five contracts impacted by C15 and C16 and the resultant impairment charge.

Implementation of these accounting changes will not impact the timing and amount of cash flows associated with the affected contracts; however, it will impact the timing and magnitude of future earnings. Future earnings will reflect the gradual reversal of the assets and liabilities recorded upon adoption over the contracts’ lives, as well as any prospective changes in the market value of the contracts. Prospective changes in the market value of these contracts could result in significant volatility in earnings. However, over the total lives of the contracts, the cumulative effect of adoption will be completely offset by subsequent changes in fair value of corresponding assets and liabilities that were recognized upon the implementation of the cited DIG issues (assuming that the affected contracts are held to their expiration).

Related Party Transactions

On October 26, 2000, PG&E GTN loaned $75 million to PG&E Corporation pursuant to a promissory note. The principal amount was payable upon demand and was included in Long-term receivables from PG&E Corporation on the consolidated balance sheet on December 31, 2001. The balance of $75 million was repaid on June 25, 2002.

As of June 30, 2002 and December 31, 2001, PG&E Corporation had issued a $16 million guarantee for an office lease relating to PG&E NEG’s San Francisco office; a guarantee related to PG&E NEG’s indemnification obligations to the purchaser of PG&E NEG’s gas transmission assets in Texas; and a guarantee related to PG&E NEG’s indemnification obligations to the purchaser of PG&E Energy Services.

As of December 31, 2001, Attala Power Corporation (APC), an indirect, wholly-owned subsidiary of the PG&E NEG, had a non-recourse demand note payable to the PG&E Corporation of $309 million. As of June 30, 2002, the balance had been reduced to $209 million. The APC note is classified as short-term on the Consolidated Balance

Sheets, as of June 30, 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 June 30, 2002, other wholly owned subsidiaries of PG&E NEG had net amounts payable in the amount of $118 million in the form of promissory notes to PG&E Corporation related primarily to past funding of generating asset development and acquisition, and are classified as long-term on the Consolidated Balance Sheets. Furthermore, on June 25, 2002, PG&E Corporation repaid a $99 million receivable related to the intercompany tax-sharing arrangement, which was included in Long-term receivables from PG&E Corporation in the accompanying Consolidated Balance Sheet at December 31, 2001.

PG&E ET enters into transactions with the Pacific Gas and Electric Company (the Utility) another wholly owned subsidiary of PG&E Corporation. The nature of these transactions is the purchase and sale of energy commodities. For the six months ended June 30, 2002 and 2001, PG&E ET had energy commodity sales of approximately $29 million and $123 million, respectively, to the Utility, and energy commodity purchases of approximately $6 million and $6 million, respectively. As of June 30, 2002, PG&E ET had trade receivables relating to energy commodity transactions from the Utility of $28 million, and trade payables relating to energy commodity transactions to the Utility of $2 million. The Utility is current on amounts owed to PG&E ET arising after the Utility’s April 6, 2001, bankruptcy filing (see note 2).

For the six months ended June 30, 2002 and 2001, the Utility accounted for approximately $22 million and $18 million of PG&E GTN’s transportation revenues, respectively. As a result of the Utility’s bankruptcy filing, 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 six months ended June 30, 2002 and 2001, allocated costs totaled $12.6 million and $11.9 million, respectively. The total amount due PG&E Corporation for these services at June 30, 2002, was $26.7 million.

In addition, PG&E NEG bills PG&E Corporation for certain shared costs. For the six months ended June 30, 2002, the total charges billed to PG&E Corporation were $2 million and for the six months ended June 30, 2001, the total charges billed were immaterial. The amounts receivable for these services from PG&E Corporation at June 30, 2002, was approximately $1 million.

NOTE 2: RELATIONSHIP WITH PG&E CORPORATION AND THE CALIFORNIA ELECTRIC INDUSTRY

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

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.

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 (Moody’s) reaffirmed investment grade ratings for PG&E GTN and PG&E Gen 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 and two guarantees of non-debt obligations of other PG&E NEG subsidiaries (except for a $16 million office lease guarantee relating to PG&E NEG’s San Francisco office and two guarantees of PG&E NEG’s indemnification obligations to purchasers of PG&E NEG’s assets) 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, primarily through its subsidiaries, engages in price risk management (PRM) activities for both non-trading and trading purposes. Non-trading activities are conducted in an effort to optimize and secure the return on risk capital deployed within PG&E NEG’s existing asset and contractual portfolio. Trading activities are conducted

to generate profit, create liquidity, and maintain a market presence. Net open positions often exist or are established due to PG&E NEG’s assessment of and response to changing market conditions.

Derivative instruments associated with non-trading activities are accounted for in accordance with SFAS No. 133. Derivatives and other financial instruments associated with trading activities in electric power and other energy commodities are accounted for using the mark-to-market method of accounting in accordance with FASB’s Emerging Issues Task Force (EITF) Issue No. 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.”

Non-Trading Activities

As of June 30, 2002, PG&E NEG had cash flow hedges of varying durations associated with commodity price, foreign currency and interest rate risk, the longest of which extend through December 2011, December 2004 and March 2014, respectively. The amount of commodity hedges included in accumulated other comprehensive income (loss) (OCI), net of taxes, as of June 30, 2002 was a gain of $98 million. The amount of interest rate hedges included in OCI, net of taxes, as of June 30, 2002 was a loss of $139 million. The amount of foreign currency hedges included in OCI, net of taxes, as of June 30, 2002 was a loss of $2 million.

PG&E NEG’s ineffective portion of changes in fair values of cash flow hedges was a $2 million gain after taxes for the three and six month periods ended June 30, 2002, and an immaterial amount for the three and six months ended June 30, 2001. PG&E NEG’s estimated net derivative losses included in OCI at June 30, 2002 are $43 million, of which net losses of $8 million are expected to be reclassified into earnings within the next 12 months. The actual amounts reclassified from accumulated other comprehensive loss to earnings will differ as a result of market price changes.

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


	Three Months			Three Months			Six Months			Six Months
	Ended			Ended			Ended			Ended
	June 30, 2002			June 30, 2001			June 30, 2002			June 30, 2001
Derivative net gains (losses) included in accumulated other comprehensive income (loss) at beginning of period	$	(34	)	$	(261	)	$	36		$	--
Cumulative effect of adoption of SFAS No. 133		—			—			—			(333	)
Net gain (loss) from current period hedging transactions and price changes		(9	)		186			(84	)		156
Net reclassification to earnings		—			10			5			112

Derivative net losses included in accumulated other comprehensive loss at end of period		(43	)		(65	)		(43	)		(65	)
Foreign currency translation adjustment		(2	)		(2	)		(2	)		(2	)

Accumulated other comprehensive loss at end of period	$	(45	)	$	(67	)	$	(45	)	$	(67	)

Trading Activities

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


		Three months ended					Six months ended
		June 30,					June 30,
		2002			2001		2002			2001

Trading activities:
	Unrealized gains and losses, net	$	(48	)	$	62	$	(53	)	$	16
	Realized gains, net		34			31		78			105

Total		$	(14	)	$	93	$	25		$	121

Unrealized gains and losses, including the reversal of unrealized gains and losses previously recognized on contracts that go to settlement or delivery, are presented on a net basis in operating revenues. Realized gains and losses are currently presented on a gross basis in operating income. The realized amounts for sale contracts are presented as operating revenues and the realized amounts for purchase contracts are presented in operating expenses as costs of commodity sales and fuel. The net realized gains of $34 million and $78 million for the three-and six months ended June 30, 2002, are composed of operating revenues of $2,387 million and $4,073 million, respectively, and operating expenses of $2,353 million and $3,995 million, respectively. Beginning in the third quarter of 2002, these realized gains and losses on trading activities will be retroactively presented on a net basis in the income statement, to comply with the consensus reached by FASB’s EITF, Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’, and No. 00-17, ‘Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10’.” PG&E NEG has reviewed its trading activities for 2001 and 2002 for potential instances of so-called “wash trades” and determined that such trades in the aggregate did not have a significant impact on revenues or expenses in any of the quarters in this period.

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

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

Price Risk Management Assets and Liabilities

Price risk management assets and liabilities on the accompanying PG&E NEG Consolidated Balance Sheets reflect the aggregation of the fair values of outstanding contracts. These fair values are calculated on a mark to market basis, for contracts that will be settled in future periods. Price risk management assets and liabilities at June 30, 2002, include amounts for trading and non-trading activities, as described below (in millions).


		PRM		PRM		PRM Liabilities			PRM Liabilities			Net PRM Assets
		Assets Current		Assets Noncurrent		Current			Noncurrent			Liabilities
*Trading activities*		$	220	$	193	$	(186	)	$	(228	)	$	(1	)

*Non-trading activities*
	Cash flow hedges – offset to OCI		283		311		(331	)		(286	)		(23	)
	Derivatives marked to market through earnings		5		70		(31	)		(237	)		(193	)

Total consolidated PRM Assets and Liabilities		$	508	$	574	$	(548	)	$	(751	)	$	(217	)

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

Credit Risk

Credit risk is the risk of loss that PG&E NEG would incur if counterparties fail to perform their contractual obligations (accounts receivable, notes receivable and price risk management assets reflected on the balance sheets). 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 mitigates potential credit losses in accordance with established credit approval practices and limits by conducting business 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 or long-form confirmations, most of which contain credit support provisions that may 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 June 30, 2002, no single customer represents greater than 10 percent of PG&E NEG’s net credit exposure.

The schedule below summarizes the exposure to counterparties that are in a net asset position, with the exception of exchange-traded futures (the exchange provides for contract settlement on a daily basis), at June 30, 2002 (in millions):


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

$974	$	81	$	893

(1) Gross credit exposure equals fair value (adjusted for appropriate credit reserves), net (payables) receivables where netting is allowed.

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

At June 30, 2002, approximately $108 million or 12 percent of PG&E NEG’s net credit exposure is to entities that have credit ratings below investment grade. Subsequent to June 30, 2002, the credit ratings of two large counterparties (Williams Companies, Inc. and Dynegy Holdings, Inc.) were reduced to below investment grade. PG&E NEG’s exposure to these companies was reduced to zero by July 29, 2002. Investment grade is determined using publicly available information including an S&P rating of at least BBB-. For counterparties that are not rated publicly, PG&E NEG performs its own analysis. Approximately $206 million or 23 percent of PG&E NEG’s net credit exposure is not rated. PG&E NEG’s regional concentrations of credit exposure are to counterparties that conduct business primarily in the western United States and also to counterparties that conduct business primarily throughout North America.

NOTE 4: DEBT FINANCING

On April 5, 2002, GenHoldings I, LLC, an indirect subsidiary of PG&E NEG, increased its committed financing from $1.075 billion to $1.460 billion. At June 30, 2002, the outstanding balance under this facility was $981 million. The increase in the facility provides for additional borrowing capacity and will provide funding for, and be secured by, an additional project, Covert, which is currently under construction. No other terms of the facility were changed.

On May 2, 2002, PG&E GTN entered into a three–year $125 million revolving credit facility, at an interest rate based on London Interbank Offer Rate (LIBOR) plus a credit spread of initially 0.725 percent. The credit spread percentage corresponds to a rating issued from time to time by S&P or Moody’s on PG&E GTN’s senior unsecured long-term debt. This three-year facility replaced a $100 million bank facility that was scheduled to expire. At June 30, 2002, there were no outstanding borrowings under this facility.

On June 6, 2002, PG&E GTN issued $100 million of 6.62 percent Senior Notes due June 6, 2012. Proceeds were used to repay $90 million of debt on its revolving credit facility, and the balance retained to meet general corporate needs. A commitment from a financial institution for a back-up 364-day bank facility, obtained in the event PG&E GTN had decided to postpone such long-term financing, was correspondingly terminated.

Interest is capitalized as a component of projects under construction. For the six months ended June 30, 2002 and 2001, PG&E NEG capitalized interest of approximately $86 million and $55 million, respectively.

NOTE 5: COMMITMENTS AND CONTINGENCIES

Commitments

PG&E NEG has substantial financial commitments in connection with agreements entered into supporting its operating, construction and development activities. These commitments are discussed more fully in the 2001 Annual Report on Form 10-K. The following summarizes significant changes to commitments since the Form 10-K was filed.

Letters of Credit: 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. The following table lists the various letter of credit facilities, that have the capacity to issue letters of credit (in millions):


						Letter of Credit
						Outstanding
Borrower	Maturity			Letter of Credit Capacity		June 30, 2002

PG&E NEG		8/02&8/03		$	650	$	184
USGenNE		9/03		$	25	$	3
PG&E Gen		12/04		$	10	$	7
PG&E ET		12/02		$	25	$	21
PG&E ET		—	⁽¹⁾	$	50	$	25
PG&E ET		11/03		$	35	$	31

(1) This letter of credit facility provides for up to $50 million of non-domestic 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.

Attala Lease: On May 10, 2002, Attala Generating Company, an indirect subsidiary of PG&E NEG, completed a $340 million sale and leaseback transaction whereby it sold and leased back its facility to a third party special purpose entity. The related lease is being accounted for as an operating lease and will amortize a deferred gain of approximately $5 million from the

sale over the lease period which is 37 years. The payment obligations under this agreement are as follows (in millions):


2002	$	49
2003		38
2004		28
2005		29
2006		27
Thereafter		631

	$	802

Attala Generating Company entered into a tolling agreement with Attala Energy Company, another wholly-owned subsidiary of PG&E NEG. Attala Energy Company’s obligations under this tolling agreement are guaranteed by a $300 million PG&E NEG guarantee.

Contingencies

PG&E NEG provides guarantees and other assistance to various subsidiaries and third parties. Some of these guarantees contain financial and other provisions that, if not met, would limit or restrict the affiliates’ access to funds under related financing arrangements, require early maturity of such guarantees, or limit the affiliates’ ability to enter into certain transactions.

The continued acceptability of many of these guarantees is dependent on PG&E NEG’s maintaining various standards of creditworthiness. On July 31, 2002, S&P downgraded PG&E NEG’s credit rating to BB+ and CreditWatch with negative implication from BBB with a stable outlook. As a result of this downgrade, PG&E NEG may be required to post replacement collateral or fund cash under those guarantees that either require an investment grade rating or contain more subjective thresholds.

Trading and non-trading hedging guarantees-PG&E NEG and its rated subsidiaries have provided $2.9 billion of guarantees to approximately 250 counterparties in support of its energy trading and non-trading hedging operations. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully utilized at any time. As of July 31, 2002, PG&E NEG and its rated subsidiaries’ aggregate exposure under these guarantees was approximately $360 million. Of this exposure, the amounts subject to securitization requirements as a result of the downgrade to below investment grade of PG&E NEG by S&P are $115 million; of PG&E ET are $16 million; and of USGenNE are $1 million. In addition, $37 million of this exposure is under guarantees that have been issued by PG&E GTN with a ratings trigger. However, the ratings trigger for PG&E GTN is not affected by S&P’s actions on July 31, 2002. The remaining $191 million could be subject to securitization requirements due to a counterparty’s concern with PG&E NEG’s or its subsidiary’s creditworthiness. As of July 31, 2002, PG&E ET had sufficient cash to cover these obligations.

Equity Commitments and Debt Repayment Guarantees-PG&E NEG has guaranteed debt or equity commitments in connection with the following (in millions):


Lake Road		$230
La Paloma		$379
Equipment Revolving Credit Facility		$230
GenHoldings I		$505

PG&E NEG has replaced the ratings triggers in these facilities with financial covenants that are consistent with those contained in PG&E NEG’s revolving credit and other loan facilities. These covenants include requirements to exceed a specified cash flow to fixed charges ratio and a specified net worth as well as maintain less than a specified total debt to total capitalization ratio and are set forth in PG&E NEG’s revolving credit agreement filed as Exhibit 10.21 to PG&E NEG’s Annual Report on Form 10-K filed with the SEC on March 5, 2002. PG&E NEG is in compliance with these covenants.

Notwithstanding the above, if PG&E NEG is also downgraded to below investment grade by Moody’s, PG&E NEG would be required to fund construction draws under the GenHoldings I financing entirely with equity until the equity commitment is fulfilled. This would result in PG&E NEG being obligated to fund approximately $270 million of additional equity through December 2002 that would have otherwise been funded through June 2003. After December 2002, the lenders would fund the construction draws pursuant to the credit agreement. Failure by PG&E NEG to fund any required equity would result in a default under the GenHoldings I credit facility as well as a default under PG&E NEG’s revolving credit facility.

Tolling arrangements-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 payment obligations of the PG&E NEG affiliate over the term of these long-term contracts (9-25 years). PG&E NEG or its rated subsidiaries has extended approximately $620 million of such guarantees. Of these guarantees, $575 million have been issued by PG&E NEG and contain a ratings trigger that requires PG&E NEG to replace the guarantee or provide alternative collateral as a result of its credit rating dropping below BBB or Baa2. This amount increases by an additional $20 million if PG&E NEG’s credit rating is also downgraded to below investment grade by Moody’s. The ratings downgrade by S&P on July 31, 2002, has triggered the need for additional guarantees, alternative collateral or other acceptable arrangements under these agreements within a ten to 30 day cure period. In the event that PG&E NEG does not replace the guarantee, provide alternative collateral or agree on other acceptable arrangements as required, the counterparty has the right to terminate the related tolling agreement and seek recovery of damages to be determined in arbitration. It is not known whether the counterparties to the tolling agreements would exercise their rights to terminate the agreements. If a party did exercise its rights to terminate a tolling agreement, the agreements generally provide that any damages are to be awarded based upon the difference in the contract price for the power under the agreement and the market price for the power, estimated by PG&E NEG to be $20 million under current conditions. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreements provide for mandatory arbitration, which could take as long as six months to more than a year to complete, depending on the specific procedures detailed in the tolling agreements. In addition, $24 million of these guarantees have been issued by PG&E GTN with a ratings trigger. However, the ratings trigger for PG&E GTN is not affected by S&P’s actions on July 31, 2002.

Other Guarantees-PG&E NEG has provided approximately $1.3 billion of guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. Of this $1.3 billion, the amount subject to securitization requirements as a result of a downgrade to below investment grade of PG&E NEG is $770 million and of PG&E GEN is $9 million. The most significant of these guarantees relate to performance under certain construction and equipment procurement contracts. In the event PG&E NEG is unable to provide the additional or replacement security required in the event of such a downgrade, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages.

These guarantees represent guarantees of subsidiary obligations for transactions entered into in the ordinary course of business. Some of the guarantees relate to the construction or development of PG&E NEG’s power plants and pipelines. Specifically, these include guarantees for the performance of the contractors building the Harquahala and Covert power projects amounting to $545 million. Any exposure under the guarantees for construction completion is mitigated by guarantees in favor of PG&E NEG from the constructor and equipment vendors related to performance, schedule and cost. Since the constructor and various equipment vendors are performing under their underlying contracts, PG&E NEG does not believe that it has significant exposure under these guarantees. Although these guarantees contain ratings triggers, the same lenders who are the beneficiaries of these guarantees are the funding banks for GenHoldings I.

PG&E NEG has provided $343 million in guarantees in favor of the various contractors and equipment vendors for the payment of any cancellation penalties in the event that projects or equipment contracts are cancelled and there remain unpaid amounts. Of this amount, approximately $58 million will be paid to these vendors for cancellation of equipment contracts. In the event that these vendors seek to terminate the contracts sooner, this amount would also represent PG&E NEG’s maximum exposure. Included in the above amount is $100 million of guarantees to the constructors of the Harquahala and Covert projects to cover certain separate cost-sharing arrangements. Failure to fund a demand for collateralization would permit the constructor to terminate those separate cost-sharing arrangements. This would not have an impact on the constructors’ obligations to complete the Harquahala and Covert projects pursuant to the contracts. Therefore, this would not have a financial impact on PG&E NEG or its subsidiaries.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement that a wholly owned subsidiary, Attala Energy Company, has entered into with Attala Generating Company. Attala Generating Company entered into a $340 million sale-lease back transaction. The tolling payments provide the lessee with sufficient cash flows to pay rent under the lease. So long as Attala Energy Company continues to perform under the tolling agreement, PG&E NEG does not believe it has any incremental liability or exposure under this guarantee.

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

Other Commitments- There is a total of $149 million in potential additional liquidity requirements related to other commitments.

In addition to the $360 million in trading exposure that is covered by guarantees and addressed above, there is an additional $73 million of current exposure under trading agreements at July 31, 2002. Some portion of this exposure is related to agreements that contain subjective language requiring additional securitization.

The remaining commitments included in the $149 million, are up to $16 million of surety bonds outstanding on behalf of PG&E NEG that may need to be replaced; transportation and storage agreement tariff provisions that may require an additional $38 million in security; incremental security to power pools that could be as much as $11 million; and miscellaneous guarantees for land options and other contracts of $11 million.

As of July 31, 2002, PG&E NEG had $728 million in unrestricted cash and $796 million of unused credit lines and letter of credit facilities. Certain of PG&E NEG’s financing instruments are due to mature in the near future. PG&E NEG is currently seeking bank commitments to renew $750 million of revolving credit that expires on August 22, 2002. As of July 31, 2002, PG&E NEG had $431 million outstanding under this facility. PG&E NEG is seeking to replace this short-term facility with a $750 million credit facility containing a $500 million two-year tranche and a $250 million 364-day tranche. In addition, PG&E NEG is seeking to refinance $609 million of debt guaranteed by PG&E NEG in connection with the Lake Road and La Paloma facilities that matures on March 31, 2003. PG&E NEG may be unable to obtain commitments for substantial portions of these financings. If PG&E NEG is unable to do so or otherwise effect acceptable arrangements, PG&E NEG’s liquidity position will be materially and adversely impacted, and PG&E NEG may be unable to satisfy demands on its liquidity.

The summary above identifies the potential demands on PG&E NEG’s liquidity as a result of S&P’s actions taken on July 31, 2002. As noted above, only the GenHoldings I equity commitment and one additional tolling agreement guarantee will be further impacted if Moody’s reduces PG&E NEG’s credit rating to below investment and one additional tolling agreement guarantee grade. The actual calls on PG&E NEG’s liquidity will depend largely upon counterparties’ reactions to the downgrade, the continued performance of PG&E NEG companies under the underlying agreements and the counterparties’ other commercial considerations. Therefore, PG&E NEG cannot predict with certainty the actual calls on PG&E NEG’s liquidity. In the past, PG&E NEG has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E NEG or its counterparties have faced similar situations. However, there can be no assurance that PG&E NEG could negotiate acceptable arrangements in the current circumstances.

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 its Brayton Point and Salem Harbor plants with the CAA. No enforcement action has been brought by the EPA to date. USGenNE has had preliminary discussions with the EPA to explore a potential settlement of this matter. Management believes that it is not possible to predict at this point whether any such settlement will occur or in the absence of a settlement the likelihood of whether the EPA will bring an enforcement action.

As a result of this and related regulatory initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to achieve significant reductions of sulfur dioxide and nitrogen oxide emissions. Additional requirements for the control of mercury and carbon dioxide emissions 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 could approximate $332 million over the next five years. These estimates are currently under review and it is possible that actual expenditures may be higher. Based on an emission control plan filed for Brayton Point under the regulations implementing these initiatives, the Massachusetts Department of Environmental Protection (DEP) ruled that Brayton Point is required to meet the newer, more stringent emission limitations for sulfur dioxide and nitrogen oxide by 2006. However, on June 7, 2002, the DEP ruled that Salem Harbor must satisfy these limitations by 2004. USGenNE will not be able to operate Salem Harbor unless it is in compliance with these emission limitations. USGenNE believes it may not be feasible to comply by 2004, and that in any event DEP improperly applied the 2004 deadline to the Salem Harbor emission control plan. USGenNE filed with DEP a revised plan for Salem Harbor in April that it believes meets the DEP requirements for the 2006 compliance date. USGenNE has also filed an administrative appeal of DEP’s ruling that Salem Harbor must meet the 2004 compliance date.

Various aspects of DEP’s regulations allow for public participation in the process through which DEP determines whether the 2004 or 2006 deadline applies and approves the specific activities that USGenNE will undertake to meet the new regulations. A local environmental group has made various filings with DEP requesting such participation.

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 (Salem Harbor, Manchester Street, and Brayton Point) are operating pursuant to National Pollutant Discharge Elimination System (NPDES) permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and all three facilities are continuing to operate under existing terms and conditions until new permits are issued. On July 22, 2002, the EPA and DEP issued a draft NPDES permit for Brayton Point that, among other things, substantially limits the discharge of heat by Brayton Point into Mount Hope Bay. Based on its initial review of the draft permit, USGenNE believes that the draft permit is excessively stringent. It is estimated that USGenNE’s cost to comply with the new permit conditions could be as much as $248 million through 2005, but this is a preliminary estimate. There are various administrative and judicial proceedings that must be completed before the draft NPDES permit for Brayton Point becoming final and these proceedings are not expected to be completed during 2002. In addition, it is possible that the new permits for Salem Harbor and Manchester Street may also contain more stringent limitations than prior permits and that the cost to comply with the new permit conditions could be greater than the current estimate of $4 million. In addition, the issuance of any final NPDES permits may be affected by EPA’s proposed regulations under Section 316(b) of the Clean Water Act.

On March 27, 2002, Rhode Island Attorney General Sheldon Whitehouse notified USGenNE of his belief that Brayton Point “is in violation of applicable statutory and regulatory provisions governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into Mount Hope Bay. He stated that he intends to seek judicial relief “to abate these environmental law violations and to recover damages...” within the next 30 days. The notice purportedly was provided pursuant to section 7A of chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. In early May, 2002, the Rhode Island Attorney General stated that he did not plan to file the action until EPA issues a draft Clean Water Act NPDES permit for Brayton Point. The EPA issued this draft permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing this matter until he reviews USGenNE’s response to the draft permit. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG’s financial condition or results of operation.

On April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using over 50 million gallons per day (mgd), typically including some form of “once-through” cooling. Brayton Point, Salem Harbor, and Manchester Street are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed rule calls for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations are scheduled to be promulgated in August 2003. The extent to which they may require additional capital investment will depend on the timing of the NPDES permit proceedings for the affected facilities. It is possible that the regulations may allow greater flexibility in achieving specified permit limits and thereby reduce the cost of compliance.

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 DEP and the environmental group to resolve these matters that require PG&E NEG to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities.

PG&E NEG began the activities during 2000, and is expected to complete them in 2003. PG&E NEG incurred expenditures related to these agreements of $5.8 million in 2000, $2.4 million in 2001and $2.0 million through June 2002. In addition to the costs previously incurred, PG&E NEG maintains a reserve in the amount of $8.0 million relating to its estimate of the remaining environmental expenditures to fulfill its obligations under 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 believes that it may be required to spend up to approximately $592 million, excluding insurance proceeds, through 2008 for environmental compliance to continue operating these facilities. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against PG&E NEG. PG&E NEG has not made any commitments to spend these amounts. In the event PG&E NEG does not spend required amounts as of each facility’s compliance deadline to maintain environmental compliance, PG&E NEG may not be able to continue to operate one or all of these facilities.

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

NSTAR Electric & Gas Corporation – On May 14, 2001, NSTAR Electric & Gas Corporation (NSTAR) the Boston-area retail electric distribution utility holding company, filed a complaint at the FERC contesting the market-based rate authority of PG&E ET-Power and affiliates of Sithe Energies, Inc. (Sithe). In support of its complaint, NSTAR argues that the Northeastern Massachusetts Area (NEMA), at times suffers transmission constraints 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

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 PG&E NEG’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 Brayton Point “is in violation of applicable statutory and regulatory provisions

governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into 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 is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. In early May, 2002 the Rhode Island Attorney General stated that he did not plan to file the action until EPA issues a draft Clean Water Act NPDES permit for Brayton Point. EPA issued this draft permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing the matter until he reviews USGenNE’s response to the draft permit. Management is unable to predict whether he will pursue this matter and if he does, the extent to which it will have a material adverse affect on PG&E NEG’s financial condition or results of operations.

NOTE 6: SEGMENT INFORMATION

PG&E NEG has two reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, and how information is reported to PG&E NEG key decision makers. The first business segment is composed of PG&E NEG’s Integrated Energy and Marketing Activities (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 and six months ended June 30, 2002, and 2001 was as follows (in millions):


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


Three Months Ended June 30, 2002
Operating revenues	$	2,999		$	54	$	2		$	3,055
Intersegment revenues⁽¹⁾		7			—		(7	)		—
Equity in earnings of affiliates		5			—		—			5


Total operating revenues		3,011			54		(5	)		3,060
Income (loss) before cumulative effect of a change in accounting principle		(190	)		17		(7	)		(180	)
Net Income (loss)		(251	)		17		(7	)		(241	)

Three Months Ended June 30, 2001⁽³⁾
Operating revenues	$	2,651		$	63	$	16		$	2,730
Intersegment revenues⁽¹⁾		2			1		(3	)		—
Equity in earnings of affiliates		23			—		—			23


Total operating revenues		2,676			64		13			2,753
Income (loss) before cumulative effect of a change in accounting principle		53			19		(1	)		71
Net income		53			19		(1	)		71

Six Months Ended June 30, 2002
Operating revenues	$	5,272		$	113	$	—		$	5,385
Intersegment revenues⁽¹⁾		9			—		(9	)		—
Equity in earnings of affiliates		23			—		—			23


Total operating revenues		5,304			113		(9	)		5,408
Income (loss) before cumulative effect of a change in accounting principle		(164	)		35		(14	)		(143	)
Net Income (loss)		(225	)		35		(14	)		(204	)

Six Months Ended June 30, 2001⁽³⁾
Operating revenues	$	6,775		$	128	$	7		$	6,910
Intersegment revenues⁽¹⁾		2			1		(3	)		—
Equity in earnings of affiliates		49			—		—			49

Total operating revenues		6,826			129		4			6,959
Income (loss) before cumulative effect of a change in accounting principle		88			38		(1	)		125
Net income		88			38		(1	)		125

Total assets at June 30, 2002	$	9,953		$	1,355	$	114		$	11,422
Total assets at June 30, 2001⁽³⁾	$	11,343		$	1,172	$	475		$	12,990

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

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

(3) As revised, See Note 1.

NOTE 7. IMPAIRMENT OF PROJECT DEVELOPMENT, TURBINES, AND OTHER RELATED EQUIPMENT COSTS

PG&E NEG has reviewed its growth plans for its electric generating business in light of the recent changes in the energy and equity markets as well as the slowdown of the U.S. economy. Further, energy prices, electric generating industry fundamentals and financial market support for competitive energy companies have significantly declined, thereby constraining access to funds at acceptable terms to PG&E NEG. Over supply of electric generation now and in the near future has significantly decreased the value of planned future development projects. In response to these market changes and considering the expected level of future electric generating supply, PG&E NEG has reconsidered the extent of, and reduced its planned investment activities in, electric generating development projects. PG&E NEG has analyzed the potential cash flow from those projects that it no longer anticipates pursuing and has recognized an impairment of the asset value it is carrying for those development projects. The aggregate pre-tax impairment charge recorded by PG&E NEG for its development assets (excluding associated equipment costs discussed below) is $19 million. The remaining asset value (recorded in Other Non Current Assets) that PG&E NEG has retained as of June 30, 2002, for its portfolio of development projects is $48 million. PG&E NEG anticipates continuing to develop these projects to completion or for future disposal and believes that their unique characteristics provide value that will enable recovery of the capitalized costs over the useful lives of the projects. PG&E NEG has no material commitments (excluding equipment costs discussed below) for the projects under continuing development.

To support PG&E NEG’s electric generating development program, PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. PG&E NEG’s commitment to purchase combustion turbines and related equipment exceeds the new planned development activities discussed above. The current electric generating market is faced with an over supply of facilities in operation and in construction. The current and future market for combustion turbines and related equipment has also seen an over supply and large cancellation of turbine orders. The net realizability of PG&E NEG’s investment in, and future committed payments for, its excess combustion turbine and related equipment portfolio, in light of current development plans, is doubtful. Based upon PG&E NEG’s current development plans and analysis of future market prices for combustion turbines and related equipment, PG&E NEG has recognized a charge of $246 million. The charge consists of the impairment of previously capitalized costs associated with prior payments made under the terms of the turbine and equipment contracts in the amount of $188 million and an accrual of $58 million for future termination payments required under the turbine and related equipment contracts. Although PG&E NEG has impaired the value of these turbines and related equipment, it has not terminated its commitments or options with respect to this equipment. The remaining asset value (recorded in Other Non Current Assets) that PG&E NEG has retained as of June 30, 2002, for its investment in turbines and related equipment is approximately $33 million. These turbine and equipment commitments have been retained to support the equipment needs for PG&E NEG’s current portfolio of advanced development projects discussed above. PG&E NEG and its equipment vendors have agreed to suspend any PG&E NEG payment obligations (except for $19 million) for at least the next twelve months. Thereafter, PG&E NEG must either restart equipment payments or, for equipment requiring progress payments, terminate such commitments and pay the associated termination costs.

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 PG&E NEG. PG&E NEG’s principal subsidiaries include: PG&E Generating Company, LLC and its subsidiaries (collectively, PG&E Gen); 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 (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&EGen 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 (MD&A) should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein. Further, this quarterly report on Form 10-Q should be read in conjunction with 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 historical results or those expressed or implied by the forward-looking statements include:

• The volatility of commodity fuel and electricity prices and the spread between them (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,

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 to which PG&E NEG’s development plans and strategies are affected by changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others;

• Future sales levels which are affected by general economic and financial market conditions, changes in interest rates, weather, conservation efforts, and outages, among other factors;

• Whether market conditions will require further impairment or write-off of PG&E NEG assets, which may cause PG&E NEG to fail to comply with the net worth requirements of its loan agreements;

• The extent to which PG&E NEG’s current or planned construction 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 construction 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 and the potential loss of permits or other rights in connection with PG&E NEG’s decision to delay or defer construction;

• PG&E NEG’s ability to obtain financing from third parties or from PG&E Corporation while preserving PG&E NEG’s credit quality; which ability could be negatively affected by conditions in the general economy or the energy markets or the capital markets, and the market’s perception of the energy industry;

• The impact on PG&E NEG of a loss of confidence in the energy industry;

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

• The impact of the recent or future downgrades in credit ratings of PG&E NEG and other subsidiaries on PG&E NEG’s and PG&E Corporation’s financial condition which will be affected by the extent to which PG&E NEG and its subsidiaries can meet liquidity calls which may be made in connection with trading activities, meet obligations to fund various equity commitments, provide other collateral to replace PG&E NEG guarantees, or obtain financing for planned development projects, whether PG&E NEG is able to renew a substantial portion of its revolving credit lines otherwise due to expire on August 22, 2002, and whether a default occurs under PG&E Corporation’s credit agreement;

• The extent to which counterparties seek damages based upon credit downgrades and their ability to recover such damages;

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

• Volatility in income resulting from mark-to-market accounting, changes to mark-to-market methodologies and the extent to which the assumptions underlying PG&E NEG’s mark-to market accounting and risk management programs are not realized;

• The effectiveness of PG&E NEG’s risk management policies and procedures ;

• 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 and changes to rules and tariffs applicable to energy marketing and trading transactions, the markets in which PG&E NEG operates, and the accounting treatment of such transactions;

• 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 PG&E NEG under certain term loans of PG&E Corporation including requirements for PG&E Corporation to comply with debt covenants regarding cash reserves, loan to value ratios, and investment grade credit ratings, among other;

• 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;

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 and the City and County of San Francisco 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 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 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 with these resulting from PG&E NEG’s marketing and trading positions. PG&E NEG manages the fuel supply and sale of electrical output 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, counterparty credit, and other market and operating risks. As of June 30, 2002, PG&E NEG had ownership or leasehold interests in 27 operating generating facilities with a net generating capacity of 7,469 megawatts (MW), as follows:

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		40
12	3,228	Natural Gas		43
3	1,166	Water		16
2	78	Wind		1

27	7,469			100

In addition, PG&E NEG has five facilities totaling 5,360 MW in construction and controls, through various arrangements, 1,149 MW in operation and 1,745 MW in construction, with a total owned and controlled generating capacity in operation or construction of 15,723 MW. PG&E NEG may sell selected operating assets in order to redeploy capital to other assets, to increase working capital and liquidity or to repay debt.

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, restructuring of 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 six month period ended June 30, 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 during the high-price period combined with a softening economy and reduced load growth have resulted in excess energy supply in many regions. The excess supply conditions have put downward pressure on the price of electricity minus the cost of fuel, or spark spread, available in most regional wholesale energy markets. Furthermore, the economic slowdown and a number of regulatory events, many of which were consequences of the California energy crisis and the Enron bankruptcy, have increased uncertainty in the energy sector.

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

Conditions in the national energy markets will constrain PG&E NEG’s near-term profitability and growth. The excess supply conditions reduce operating margins for electric generators and lower price volatility for energy products, potentially reducing profits from energy trading activities. In response to these market changes, PG&E NEG has reconsidered the extent of and reduced its planned investment activities in electric generating development projects. PG&E NEG has analyzed the potential cash flow from those projects that it no longer anticipates pursuing and has recognized an impairment of the carrying value of those development projects and the associated turbine and equipment assets. This impairment, described under “Investing Activities” below, reflects PG&E NEG’s judgment that the market viability of these development projects is uncertain. PG&E NEG is continuing to seek purchasers or partners for these development projects and the equipment associated with them. PG&E NEG also initiated a program to reduce administrative, general and other operating costs, with a targeted annual reduction of a minimum of $40 million.

In addition, a series of events and disclosures have created a more difficult financial and regulatory climate for the energy industry and its participants, including PG&E NEG. S&P announced that it has changed its methodology to review energy industry participants, and has recently issued several downgrades. On July 31, 2002, S&P downgraded PG&E NEG to BB+ from BBB. See “Credit Ratings and Liquidity Uses” below.

In addition, investigations are underway by state and federal authorities into energy trading matters. In response to a data request order from FERC, PG&E NEG conducted an investigation into certain activities of its subsidiaries in the U.S. portion of the Western Systems Coordinating Council (“WSCC”) during the years 2000 and 2001. FERC requested information regarding transactions in which energy traders simultaneously engaged in any purchase and sale of the same product at the same price with the same counterparty in the WSCC during the years 2000 and 2001. As a result of its investigation, PG&E NEG identified 12 such instances. In addition, PG&E NEG has reviewed its activities including those in other regions during the period January 2000 through May 2002 using the FERC criteria and has identified 32 additional instances. These instances had no material effect on PG&E NEG’s reported revenues or financial results. Revenues associated with these instances represent approximately 0.14 percent of PG&E NEG’s revenues during the same period.

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 advanced gas turbine technology; including many of those PG&E NEG has 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) may no longer be available on commercially reasonable terms, deductibles will increase in size and premiums will be significantly higher. Therefore, PG&E NEG will likely carry a greater percentage of self-insurance at potential risk of greater losses than in prior periods.

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 has been 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. PG&E NEG’s credit ratings have been important to PG&E NEG’s ability to provide counterparty guarantees and to obtain capital.

Credit Ratings and Liquidity Uses

The credit ratings as of July 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 (PG&E NEG)	BB+	Baa2
Senior Unsecured Notes due 2005 (PG&E GTN)	BBB+	Baa1
Senior Unsecured Debentures due 2025 (PG&E GTN)	BBB+	Baa1
Medium Term Notes (nonrecourse) PG&E GTN	BBB+	Baa1
Outstanding Credit Facilities	Various	Various
Term Loan – GenHoldings I, LLC	BBB-	Baa3
Mortgage Loans and Other	Not Rated	Not Rated

On July 31, 2002, S&P downgraded PG&E NEG to BB+ from BBB. On the same date S&P downgraded PG&E ET to BB+ from BBB+, PG&E GTN to BBB+ from A-, PG&E Gen to BB+ from BBB, and USGenNE to BB+ from BBB-. All of the rated companies have also been placed on CreditWatch with negative implications. In April 2002, Moody’s affirmed PG&E NEG’s Baa2 rating, but changed the outlook for PG&E NEG to negative from stable. The downgrade of PG&E NEG’s credit ratings impacts certain guarantees and financial arrangements that require PG&E NEG to maintain certain credit ratings from S&P and/or Moody’s. These provisions are referred to as “ratings triggers.” Generally, the ratings triggers are linked to one or more investment grade ratings. PG&E NEG’s counterparties generally hold guarantees from PG&E NEG or a rated subsidiary of PG&E NEG, usually PG&E ET or PG&E GTN.

In addition to agreements containing ratings triggers, other agreements allow counterparties to seek additional security for performance whenever such counterparty becomes concerned about PG&E NEG’s or its subsidiaries’ creditworthiness. The downgrades could give rise to such concerns. As a result of the rating triggers or other demand for security, PG&E NEG may be required to provide additional collateral in the form of cash, letters of credit or replacement guarantees or to fund obligations in advance of their expected schedules. The amount of this additional security or funding varies depending upon PG&E NEG’s current exposure under its agreements and the reactions to the downgrades of counterparties holding PG&E NEG’s guarantees. This funding or provision of additional collateral may significantly deplete or exceed PG&E NEG’s liquidity resources.

Ratings triggers and additional security obligations are generally a feature of five categories of PG&E NEG agreements: (1) trading and non-trading hedging agreements and related guarantees, (2) tolling agreement guarantees, (3) debt repayment or equity commitments in connection with asset-specific debt arrangements, (4) guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services and (5) other contractual commitments to third parties.

Trading and non-trading hedging guarantees-PG&E NEG and its rated subsidiaries have provided $2.9 billion of guarantees to approximately 250 counterparties in support of its energy trading and non-trading hedging operations. Typically, the overall exposure under these guarantees is only a fraction of the face value of these guarantees, since not all counterparty credit limits are fully utilized at any time. As of July 31, 2002, PG&E NEG and its rated subsidiaries’ aggregate exposure under these guarantees was approximately $360 million. Of this exposure, the amounts subject to securitization requirements as a result of a downgrade to below investment grade of PG&E NEG are $115 million; of PG&E ET are $16 million; and of USGenNE are $1 million. In addition, $37 million of this exposure is under guarantees that have been issued by PG&E GTN with a ratings trigger. However, the ratings trigger for PG&E GTN is not affected by S&P’s actions on July 31, 2002. The remaining $191 million could be subject to securitization requirements due to a counterparty’s concern with PG&E NEG’s or its subsidiary’s creditworthiness. As of July 31, 2002, PG&E ET had sufficient cash to cover these obligations.

Equity Commitments and Debt Repayment Guarantees-PG&E NEG has guaranteed debt or equity commitments in connection with the following (in millions):


Lake Road		$230
La Paloma		$379
Equipment Revolving Credit Facility		$230
GenHoldings I		$505

Tolling arrangements-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 payment obligations of the PG&E NEG affiliate over the term of these long-term contracts (9-25 years). PG&E NEG or its rated subsidiaries has extended approximately $620 million of such guarantees. Of these guarantees, $575 million have been issued by PG&E NEG and contain a ratings trigger that requires PG&E NEG to replace the guarantee or provide alternative collateral as a result of its credit rating dropping below BBB or Baa2. This amount increases by an additional $20 million if PG&E NEG’s credit rating is also downgraded to below investment grade by Moody’s. The ratings downgrade by S&P on July 31, 2002, has triggered the need for additional guarantees, alternative collateral or other acceptable arrangements under these agreements within a ten to 30 day cure period. In the event that PG&E NEG does not replace the guarantee, provide alternative collateral or agree on other acceptable arrangements as required, the counterparty has the right to terminate the related tolling agreement and seek recovery of damages to be determined in arbitration. It is not known whether the counterparties to the tolling agreements would exercise their rights to terminate the agreements. If a party did exercise its right to terminate a tolling agreement, the agreements generally provide that any damages are to be awarded based upon the difference in the contract price for the power under the agreement and the market price for the power, estimated by PG&E NEG to be $20 million under current conditions. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreements provide for mandatory arbitration, which could take as long as 6 months to more than a year to complete, depending on the specific procedures detailed in the tolling agreements. In addition, $24 million of these guarantees have been issued by PG&E GTN with a ratings trigger. However, the ratings trigger for PG&E GTN is not affected by S&P’s actions on July 31, 2002.

Other Guarantees-PG&E NEG has provided approximately $1.3 billion of guarantees related to other obligations by PG&E NEG companies to counterparties for goods or services. Of this $1.3 billion, the amount subject to securitization requirements as a result of the downgrade to below investment grade of PG&E NEG is $770 million and PG&E Gen is $9 million. The most significant of these guarantees relate to performance under certain construction and equipment procurement contracts. In the event PG&E NEG is unable to provide the additional or replacement security required in the event of such a downgrade, the counterparty providing the goods or services could suspend performance or terminate the underlying agreement and seek recovery of damages.

PG&E NEG has provided $343 million in guarantees in favor of the various contractors and equipment vendors for the payment of any cancellation penalties in the event that projects or equipment contracts are cancelled and there remain unpaid amounts. Of this amount, approximately $58 million will be paid to these vendors for cancellation of equipment contracts. In the event that these vendors seek to terminate the contracts sooner, this amount would also represent PG&E NEG’s maximium exposure. Included in the above amount is $100 million of guarantees to the constructor of the Harquahala and Covert projects to cover certain separate cost–sharing arrangements. Failure to fund a demand for collaterization would permit the constructor to terminate those separate cost–sharing arrangements. This would not have an impact on the constructors' obligations to complete the Harquahala and Covert projects pursuant to the contracts. Therefore, this would not have a financial impact on the PG&E NEG or its subsidiaries.

Other Commitments — There is a total of $149 million in potential additional liquidity requirements related to other commitments.

The remaining commitments included in the $149 million are up to $16 million of surety bonds outstanding on behalf of PG&E NEG that may need to be replaced; transportation and storage agreement tariff provisions that may require an additional $38 million in security; incremental security to power pools that could be as much as $11 million; and miscellaneous guarantees for land options and other contracts of $11 million.

Liquidity Resources

The summary above identifies the potential demands on PG&E NEG’s liquidity as a result of S&P’s actions taken on July 31, 2002. As noted above, only the GenHoldings I equity commitment and one additional tolling agreement guarantee will be further impacted if Moody’s reduces PG&E NEG’s credit rating to below investment grade. The actual calls on PG&E NEG’s liquidity will depend largely upon counterparties’ reactions to the downgrade, the continued performance of PG&E NEG companies under the underlying agreements and the counterparties’ other commercial considerations. PG&E NEG has reviewed its anticipated sources and uses of liquidity in light of the impact of the S&P downgrade and current market conditions. The following table provides an estimate of PG&E NEG’s potential sources and uses of cash for the next twelve months and is based upon the assumptions regarding exposure and negotiations with and payments to counterparties and calls on PG&E NEG’s liquidity set forth above (in millions):


Potential sources of cash
	Cash on hand at July 31, 2002		728
	Estimated operating cash flow (1)		500
	Financings
		Available capacity under two-year $500 million revolver	310
		Available capacity under one year $750 million revolver to be renewed August 22, 2002 (2)	319
		Available capacity under USGenNE $100 million credit facility	22
		Available capacity under PG&E GTN $125 million facility (3)	125
		Available capacity under other credit facilities with $120 million capacity	20
		Facility financing on GenHoldings I for construction costs (4)	266
		Refinancing of Lake Road/La Paloma required by March 31, 2003	609
		Other non-recourse financings in progress (5)	125
	Other sources of cash		65

Total Potential Sources of Cash			3,089

Potential uses of cash
	Operating and debt service cost		314
	Capital requirements for current construction program		974
	Payment for equipment termination and repayment of equipment revolver		126
	Potential collateral requirements for asset business (6)		76
	Maximum cash collateral requirements on trading (7)		323
	Lake Road/La Paloma loan maturity		609

Total Potential Uses of Cash			2,422


Net Potential Surplus Liquidity			667


(1)		Distribution and dividends from PG&E NEG subsidiaries
(2)		One year revolver facility due for renewal August 22, 2002: $431 million outstanding at July 31, 2002.
(3)		PG&E GTN debt capacity is only available for affiliated entities to extent PG&E NEG can meet certain
		ring-fencing restrictions
(4)		Five year facility, net of letters of credit and working capital to support underlying projects.
(5)		Non-recourse financing for operating projects with cash to be available to PG&E NEG under current
		conditions.
(6)		Covers pipeline transport, gas storage and power pool collateral requirements
(7)		Exposure for all trading agreements having financial covenants for subinvestment grade entities

PG&E NEG cannot predict with certainty the actual calls on PG&E NEG’s liquidity. In the past, PG&E NEG has been able to negotiate acceptable arrangements and reduce its overall exposure to counterparties when PG&E NEG or its counterparties have faced similar situations. However, there can be no assurance that PG&E NEG could negotiate acceptable arrangements in the current circumstances.

As the table above indicates, as of July 31, 2002, PG&E NEG had $728 million in unrestricted cash and $796 million of unused credit lines and letter of credit facilities. Certain of PG&E NEG’s financing instruments are due to mature in the near future. PG&E NEG is currently seeking bank commitments to renew $750 million of revolving credit that expires on August 22, 2002. As of July 31, 2002, PG&E NEG had $431 million outstanding under this facility. PG&E NEG is seeking to replace this short-term facility with a $750 million credit facility containing a $500 million two-year tranche and a $250 million 364-day tranche. In addition, PG&E NEG is seeking to refinance $609 million of debt guaranteed by PG&E NEG in connection with the Lake Road and La Paloma facilities that matures on March 31, 2003. PG&E NEG may be unable to obtain commitments for substantial portions of these financings. If PG&E NEG is unable to do so or otherwise effect acceptable arrangements, PG&E NEG’s liquidity position will be materially and adversely impacted, and PG&E NEG may be unable to satisfy demands on its liquidity.

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, PG&E GTN and the subsidiaries that own 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 2.25 to 1.00 and a consolidated leverage ratio of less than or equal to 0.70 to 1.00.

During the six months ended June 30, 2002, PG&E NEG generated net cash from operations of $18 million compared to net cash from operations of $34 million for the same period in 2001, or a decrease of $16 million. Increases in net income including adjustments to reconcile net income to net cash provided in operations activities, improved operating cash flow by $69 million period to period. The increase from period to period was primarily due to net price risk management activities. Offsetting this increase in cash flow from operations was a decrease due to the net effect of changes in operating assets and liabilities of $85 million period to period. Included in Investing Activities is a cash flow of $42 million related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities.

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

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 six months ended June 30, 2002, PG&E NEG used net cash of $530 million in investing activities compared to $673 million for the same period in 2001, or a decrease of $143 million. The decrease in investing activities from period to period were primarily due to proceeds from the Attala Generating Company sale leaseback transaction providing $340 million and the repayment of a $75 million loan to PG&E Corporation from PG&E GTN both occurring in the second quarter 2002. Offsetting these proceeds were increased construction expenditures of $900 million for the six months ended June 30, 2002, versus $473 million for the six months ended June 30, 2001. Advanced development and turbine prepayments were $6 million and $173 million for the six month periods June 30, 2002 and 2001, respectively. Other net expenditures were $39 million and $27 million for the six months ended June 30, 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 five generating facilities under construction. The table below outlines the expected dates that these will be completed.

Percentage

Projected

Projects

Location

Completion

In-Service Dates

Athens

New York

53%

3rd Quarter, 2003

Covert

Michigan

41%

3rd Quarter, 2003

Harquahala

Arizona

45%

3rd Quarter, 2003

La Paloma

California

98%

4th Quarter, 2002

Mantua Creek

New Jersey

18%

Undetermined

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 entered into a construction contract for the Mantua Creek project and released the contractor to perform early construction activities; however, full mobilization of the construction contractor has not taken place and unrestricted construction has been delayed. As of June 30, 2002, PG&E NEG had recorded assets of $244 million for Mantua Creek, representing equipment payments, construction activities, and development costs. The interconnection arrangements for the Mantua Creek project currently require that Mantua Creek achieve commercial operation by June 2004. PG&E NEG is seeking an extension of this deadline. If PG&E NEG is unable to obtain such an extension, PG&E NEG may be required to accelerate current construction activities and increase expenditures accordingly in order to preserve its investment in Mantua Creek. This acceleration of costs could put additional pressure on PG&E NEG’s liquidity position. PG&E NEG continues to explore options to find a partner for, or to finance or sell, the project.

PG&E NEG has executed construction contracts, excluded from above, 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

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

MW of turbines for the Smithland project, but had suspended construction because recently stated seismic requirements caused a reevaluation of the project’s design in connection with the Army Corps of Engineers permit. PG&E NEG believes that satisfying the new seismic criteria will not require any design changes and that the Army Corps of Engineers will concur. Pending such concurrence, PG&E NEG has not restarted construction.

Generating Projects in Development—PG&E NEG has reviewed its growth plans for its electric generating business in light of the recent changes in the energy and equity markets as well as the slowdown of the U.S. economy. Further, energy prices, electric generating industry fundamentals and financial markets support for competitive energy companies have significantly declined, thereby constraining access to funds at acceptable terms to PG&E NEG. Over supply of electric generation now and in the near future has significantly decreased the value of planned future development projects. In response to these market changes and considering the expected level of future electric generating supply, PG&E NEG has reconsidered the extent of, and reduced its planned investment activities in, electric generating development projects. PG&E NEG has analyzed the potential cash flow from those projects that it no longer anticipates pursuing and has recognized an impairment of the asset value it is carrying for those development projects. The aggregate pre-tax impairment charge recorded by PG&E NEG for its development assets (excluding associated equipment costs discussed below) is $19 million. The remaining asset value (recorded in Other Non Current Assets) that PG&E NEG has retained as of June 30, 2002, for its portfolio of development projects is $48 million. PG&E NEG anticipates continuing to develop these projects to completion or for future disposal and believes that their unique characteristics provide value that will enable recovery of the capitalized costs over the useful lives of the projects. PG&E NEG has no material commitments (excluding equipment costs discussed below) for the projects under continuing development.

Turbine Purchase Commitments—To support PG&E NEG’s electric generating development program, PG&E NEG had contractual commitments and options to purchase a significant number of combustion turbines and related equipment. PG&E NEG’s commitment to purchase combustion turbines and related equipment exceeds the new planned development activities discussed above. The current electric generating market is faced with an over supply of facilities in operation and in construction. The current and future market for combustion turbines and related equipment has also seen an over supply and large cancellation of turbine orders. The net realizability of PG&E NEG’s investment in, and future committed payments for, its excess combustion turbine and related equipment portfolio, in light of current development plans, is doubtful. Based upon PG&E NEG’s current development plans and analysis of future market prices for combustion turbines and related equipment, PG&E NEG has recognized a charge of $246 million. The charge consists of the impairment of previously capitalized costs associated with prior payments made under the terms of the turbine and equipment contracts in the amount of $188 million and an accrual of $58 million for future termination payments required under the turbine and related equipment contracts. Although PG&E NEG has impaired the value of these turbines and related equipment, it has not terminated its commitments or options with respect to this equipment. The remaining asset value (recorded in Other Non Current Assets) that PG&E NEG has retained as of June 30, 2002, for its investment in turbines and related equipment is approximately $33 million. These turbine and equipment commitments have been retained to support the equipment needs for PG&E NEG’s current portfolio of advanced development projects discussed above. PG&E NEG and its equipment vendors have agreed to suspend any PG&E NEG payment obligations (except for $19 million) for at least the next twelve months. Thereafter, PG&E NEG must either restart equipment payments or, for equipment requiring progress payments, terminate such commitments and pay the associated termination costs.

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 (MMcf) per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001 and 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 of which $118 million has been spent through June 30, 2002. FERC has issued a preliminary determination on non-environmental matters authorizing PG&E GTN to complete a second expansion of approximately 150 MMcf per day of additional capacity, at a cost of approximately $111 million. PG&E GTN is evaluating plans for the timing of the second expansion and may defer its construction. PG&E GTN expects to fund these expansions from cash provided by operations, external financing, and capital contributions from PG&E NEG.

PG&E GTN regularly solicits expressions of interest for the acquisition or development of additional pipeline capacity and may develop additional firm transportation capacity as sufficient demand is demonstrated. PG&E GTN has also initiated a preliminary assessment of lateral pipelines that would originate at the PG&E GTN mainline system and extend to metropolitan areas in the Pacific Northwest.

North Baja Pipeline—PG&E NEG has begun construction 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. At June 30, 2002, PG&E NEG had spent approximately $100 million on this project. 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 $140 million. PG&E NEG expects to fund this project from the issuance of debt, and available cash or draws on available lines of credit.

The California State Lands Commission is a defendant and, along with North Baja, is a real party in interest 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 and other issues as required by the California Environmental Quality Act (CEQA). The claim seeks an injunction restraining construction of the pipeline, but no request for a temporary restraining order was filed. Therefore construction of the project is underway. PG&E NEG intends to vigorously participate in the lawsuit. A hearing on the merits of the case is scheduled for August 30, 2002.

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 six months ended June 30, 2002, and 2001, PG&E NEG provided net cash flows from financing activities of $553 million and $702 million, respectively. This decrease is primarily related to the timing of construction funding needed for the Athens, La Paloma, Covert and Harquahala projects.

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

RISK MANAGEMENT ACTIVITIES

PG&E NEG has established risk management policies that allow the use of energy, currency, 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, and operational risks. Such derivatives include forward contracts, futures, swaps, options, and other contracts.

• Forward contracts are commitments to purchase or sell energy commodities in the future;

• Futures contracts are standardized commitments to purchase or sell an energy commodity or financial instrument at a specific price and future date;

• Swap agreements require payments to or from counterparties for a quantity based upon the difference between agreed upon prices, at least one of which is an index;

• Option contracts provide the right to buy or sell the underlying instrument at a specified price;

PG&E NEG uses derivatives for both trading (for profit) and non-trading (hedging) purposes. Trading activities may be done for purposes of generating profits, gathering market intelligence, creating liquidity, maintaining a market presence and taking a market view. Non-trading activities may be done for purposes of hedging the risks associated with an asset, liability, committed transaction, or probable forecasted transaction.

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


	Three Months Ended			Six Months Ended
	June 30, 2002⁽¹⁾			June 30, 2002⁽¹⁾

Fair values of trading contracts at beginning of period	$	31		$	33
Net gain on contracts settled during the period		34			78
Changes in fair values attributable to changes in valuation techniques and assumptions		—			—
Other changes in fair values		(66	)		(112	)

Fair values of trading contracts outstanding at end of period	$	(1	)	$	(1	)
Fair value of non-trading contracts		(216	)		(216	)

Net price risk management liabilities at end of period	$	(217	)	$	(217	)

(1) For the three and six months ended June 30, 2002, the fair value of all new contracts when entered into was zero.

PG&E NEG estimated the gross mark-to-market value of its trading contracts as of June 30, 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. Most of PG&E NEG’s risk management models are reviewed by or purchased from third-party experts with extensive experience in specific derivative applications. The fair value of trading contracts also includes deductions for time value, credit, model, and other adjustments necessary to determine fair value.

The weighted average maturity of PG&E NEG’s entire portfolio of trading contracts was approximately one year as of June 30, 2002. The following table shows the mark-to-market and cash flow value of PG&E NEG’s trading contracts by maturity at June 30, 2002 (in millions):


				Fair Value of Trading Contracts⁽²⁾ at June 30

										Maturity
	Maturity			Maturity			Maturity			in Excess			Total
	Less Than			One-Three			Four-Five			of Five			Fair
	One Year			Years			Years			Years			Value

Source of Prices used in Estimating Fair Value
Actively quoted	$	59		$	(38	)	$	(7	)	$	(4	)	$	10
Provided by other external sources		—			—			(43	)		66			23
Based on models and other valuation methods⁽¹⁾		(21	)		(29	)		1			15			(34	)
Total Mark to Market	$	38		$	(67	)	$	(49	)	$	77		$	(1	)

(1) 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.

(2) Excludes all non-trading contracts, including non-trading contracts that are recorded at fair value through earnings.

The amounts disclosed above are not indicative of likely future cash flows, as these positions may be impacted by change in underlying valuations, new transactions in the trading portfolio in response to changing market conditions, market liquidity, and PG&E NEG’s risk management portfolio needs and strategies.

Market Risk —Market risk is the risk that changes in market conditions will adversely affect earnings or cash flow. Such risks include price risk, credit risk, interest rate risk, and foreign currency risk and may impact PG&E NEG’s asset and trading portfolio.

Price Risk—Price risk is the risk that changes in market prices of a commodity or other instrument will adversely affect earnings or cash flows. PG&E NEG is exposed to price risk for its portfolio of electric generation assets and supply contracts that serve wholesale and industrial customers, and with respect 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 its forecasted generation. PG&E NEG is also exposed to commodity price risk for net open positions within its trading portfolio due to the assessment of and response to changing market conditions.

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 parametric 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 holding 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 price risk for June 30, 2002 (in millions):


Trading Activities		$	3.8
Non – Trading Activities:
	Non-Trading Contracts that Receive Mark To Market Accounting Treatment⁽¹⁾	$	3.9
	Non-Trading Contracts Accounted for as Hedges⁽²⁾	$	13.9

(1) Includes derivative power and fuels contracts that do not qualify to be accounted for as cash flow hedges or are exempted from SFAS No. 133 as normal purchases and sales.

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

Parametric 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 risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. As of June 30, 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

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 June 30, 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 (accounts receivable, notes receivable and price risk management assets reflected on the balance sheet). 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 mitigates potential credit losses in accordance with established credit approval practices and limits by conducting business 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 or long-form confirmations, most of which contain credit support provisions that may 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 June 30, 2002, no single customer represent greater than 10 percent of PG&E NEG’s net credit exposure.


Gross	Credit
Exposure⁽¹⁾	Collateral⁽²⁾		Net Exposure⁽²⁾
$974	$	81	$	893

(1) Gross credit exposure equals fair value (adjusted for applicable credit reserves), net (payables) receivables where netting is allowed.

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

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

RESULTS OF OPERATIONS

The table shows for the three months and six months ended June 30, 2002 and 2001, certain items from the accompanying Consolidated Statements of Operations detailed by reportable segments of PG&E NEG. (In the “Total” column, the table shows the combined results of operations for those items.) The information for PG&E NEG (the “Total” column) includes the appropriate intercompany elimination. Results of operations are discussed following this table (in millions).


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


Three months ended June 30, 2002
Total operating revenues	$	3,011		$	54	$	(5	)	$	3,060
Total operating expenses		3,320			25		(5	)		3,340

Total operating income		(309	)		29		—			(280	)


Interest income										16
Interest expense										56
Other income (expense), net										(6	)
Income (loss) before income tax										(326	)
Income taxes benefit										(146	)
Income (loss) before cumulative effect of a change in accounting principle										(180	)
Net income (loss)										(241	)
Net cash used by operating activities										(66	)
Net cash used in investing activities										(153	)
Net cash provided by financing activities										294
EBITDA (2)		(285	)		44		(4	)		(245	)

Three months ended June 30, 2001 (as revised, see Note 1 of the Notes to the Consolidated Financial Statements)
Total operating revenues		2,676			64		13			2,753
Total operating expenses		2,595			25		8			2,628

Total operating income		81			39		5			125


Interest income										24
Interest expense										31
Other income (expense), net										1
Income before income tax										119
Income taxes provision										48
Net Income										71
Net cash provided by operating activities										226
Net cash used in investing activities										(408	)
Net cash provided by financing activities										536
EBITDA (2)		108			49		6			163


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


For the six months ended June 30, 2002
Total operating revenues	$	5,304		$	113	$	(9	)	$	5,408
Total operating expenses		5,576			51		—			5,627


Total operating income		(272	)		62		(9	)		(219	)


Interest income										32
Interest expense										89
Other income (expense), net										(3	)
Income (loss) before income tax										(279	)
Income taxes benefit										(136	)
Income (loss) before cumulative effect of a change in accounting principle										(143	)
Net income (loss)										(204	)
Net cash provided by operating activities										18
Net cash used in investing activities										(530	)
Net cash provided by financing activities										553
EBITDA (2)		(214	)		90		(9	)		(133	)

For the six months ended June 30, 2001 (as revised, see Note 1 of the Notes to the Consolidated Financial Statements)
Total operating revenues		6,826			129		4			6,959
Total operating expenses		6,692			50		7			6,749


Total operating income		134			79		(3	)		210


Interest income										49
Interest expense										58
Other income (expense), net										6
Income before income tax										207
Income taxes provision										82
Net Income										125
Net cash provided by operating activities										34
Net cash used in investing activities										(673	)
Net cash provided by financing activities										702
EBITDA (2)	$	192		$	99	$	—		$	291

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.

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

Three Months Ended June 30, 2002 as Compared to Three Months Ended June 30,
2001

Overall Results: PG&E NEG’s net loss (after cumulative effect of a change in accounting principle) was $241 million for the three months ended June 30, 2002, a decrease of $312 million from the three months ended June 30, 2001.

PG&E NEG’s pre-tax operating income for the six months ended June 30, 2002, compared to the same period in the prior year decreased $405 million mainly due to impairments and write-offs of long-term turbine prepayments and related capitalized development costs of approximately $265 million. Also contributing to the decline in pre-tax operating income were lower gross margins principally related to operations in New England and PG&E ET; higher operations and maintenance costs and higher depreciation due to the start-up of new plants. Interest expense was higher primarily due to the PG&E NEG $1 Billion Senior Notes which were issued late in the second quarter of 2001.

The three months ended June 30, 2002 included a net loss for the cumulative effect of a change in accounting principle of $61 million. The cumulative effect was based on PG&E NEG’s adoption as of April 1, 2002, of interpretations issued by the Derivatives Implementation Group (DIG), DIG C15 and DIG C16, reflecting the mark-to-market value of certain contracts that had previously been accounted under the accrual method as normal purchases and sales.

Operating Revenues: PG&E NEG’s operating revenues were $3.060 billion in the three months ended June 30, 2002, an increase of $307 million from the three months ended June 30, 2001. This increase occurred in the Integrated Energy and Marketing Activities segment with a slight decline in revenue from Interstate Pipeline Operations. PG&E NEG’s wholesale energy trading revenues, included in the Integrated Energy and Marketing Activities segment, increased as a result of settled volume increases compared to the prior year. Settled volume increases were somewhat offset by declines in commodity prices and continued compressed spark spreads through the second quarter in 2002 as compared to the same period last year. Interstate Pipeline Operations operating revenues declined $10 million due to weak pricing fundamentals on gas transportation to the California and Pacific Northwest gas markets compared to the same period last year.

Operating Expenses: PG&E NEG’s operating expenses were $3.340 billion in the three month period ended June 30, 2002, a increase of $712 million from the same period in the prior year. These increases occurred primarily in the Integrated Energy and Marketing segment. The cost of commodity sales and fuel increased $458 million in line with, but greater than, the increases in operating revenues within the wholesale energy trading business. During the second quarter of 2002, PG&E NEG recognized an impairment charge of approximately $265 million of previously capitalized turbine prepayments and related capitalized development costs. In addition, operations, maintenance and management costs increased $20 million in the second quarter of 2002 as compared to the same period last year principally due to the operations of new plants coming on line. In addition, depreciation and amortization costs increased $4 million in the period also mainly due to new plants coming on line. Offsetting these increases in operating costs was a decline in other operating expenses.

Six Months Ended June 30, 2002 as Compared to Six Months Ended June 30, 2001

Overall Results: PG&E NEG’s net loss (after cumulative effect of a change in accounting principle) was $204 million for the six months ended June 30, 2002, a decrease of $329 million from the six months ended June 30, 2001. The six months ended June 30, 2002 included a net loss for the cumulative effect of a change in accounting principle of $61 million. The cumulative effect was based on PG&E NEG’s adoption as of April 1, 2002, interpretations issued by the Derivatives Implementation Group (DIG), DIG C15 and DIG C16, reflecting the mark-

to-market value of certain contracts that had previously been accounted for under the accrual basis as normal purchases and sales.

PG&E NEG’s pre-tax operating income decreased $429 million mainly due to impairments and write-offs of long-term turbine prepayments and related capitalized development costs of approximately $265 million. Also contributing to the decline in pre-tax operating income were lower gross margins principally related to operations in New England and PG&E ET; higher operations and maintenance costs and higher depreciation due to the start-up of new plants. Offsetting these declines in pre-tax operating income was a decline in administrative and general costs primarily related to lower employee related expenses in the first quarter of 2002. Interest expense was higher primarily due to the PG&E NEG $1 Billion Senior Notes which were issued late in the second quarter of 2001. PG&E NEG’s tax benefits for the six months ended June 30, 2002 were based on reduced income levels as compared to the same period last year and 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 $5.408 billion in the six months ended June 30, 2002, a decrease of $1.551 billion from the six months ended June 30, 2001. These declines occurred primarily in the Integrated Energy and Marketing Activities segment. The principle driver in this decrease was in PG&E NEG’s wholesale energy trading business, primarily due to a decline in commodity prices and significantly compressed spark spreads in 2002 as compared to the same period last year. Interstate Pipeline Operations operating revenues declined $16 million due to weak pricing fundamentals on gas transportation to the California and Pacific Northwest gas markets compared to the same period last year.

Operating Expenses: PG&E NEG’s operating expenses were $5.627 billion in the six month period ended June 30, 2002, a decrease of $1.122 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 $1.389 billion in line with the declines in operating revenues within the wholesale energy trading business. Included in operating expenses is approximately $265 million of impairment charge relative to previously capitalized turbine prepayments and related capitalized development cost. In addition, operations, maintenance and management costs increased $35 million in 2002 as compared to the same period last year principally due to new plants coming on line. In addition, depreciation and amortization costs increased $14 million in the period also mainly due to new plants coming on line.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

In August 2001, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Statements (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 April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections.” This statement eliminates the current requirement that gains and losses on debt extinguishment must be classified as extraordinary items in the income statement. Instead, such gains and losses will be classified as extraordinary items only if they are deemed to be unusual and infrequent, in accordance with the current GAAP criteria for extraordinary classification. In addition, SFAS 145 eliminates an inconsistency in lease accounting by requiring that modifications of capital leases that result in reclassification as operating leases be accounted for consistent with sale-leaseback accounting rules. The statement also contains other

nonsubstantive corrections to authoritative accounting literature. The changes related to debt extinguishment will be effective for fiscal years beginning after May 15, 2002, and the changes related to lease accounting will be effective for transactions occurring after May 15, 2002. Adoption of this standard will not have any immediate effect on PG&E NEG’s consolidated financial statements. PG&E NEG will apply this guidance prospectively.

On June 20, 2002, the FASB’s Emerging Issues Task Force (EITF) reached a partial consensus on Issue No. 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF Issues No. 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’, and No. 00-17, ‘Measuring the Fair Value of Energy-Related Contracts in Applying Issue No. 98-10’.” The EITF concluded that, effective for periods ending after July 15, 2002, mark-to-market gains and losses on energy trading contracts (includes those to be physically settled) must be retroactively presented on a net basis in earnings. Also, companies must disclose volumes of physically-settled energy trading contracts. PG&E NEG is evaluating the impact of this new consensus on the presentation of its consolidated income statement but believes it will have a material impact on total revenues and expenses. The consensus will have no impact on net income.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3. PG&E NEG will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. Under EITF No. 94-3, a liability for an exit cost was recognized at the date of a company’s commitment to an exit plan. SFAS No. 146 also establishes that the liability should initially be measured and recorded at fair value. Accordingly, SFAS No. 146 may affect the timing of recognizing future restructuring costs as well as the amount recognized.

NEW ACCOUNTING POLICIES

On April 1, 2002, PG&E NEG implemented two interpretations issued by the FASB’s Derivatives Implementation Group (DIG). DIG Issues C15 and C16, that changed the definition of normal purchases and sales included in 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” and ongoing interpretation of the FASB’s DIG (collectively, SFAS No. 133). Previously, certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business were exempt from the requirements of SFAS No. 133 under the normal purchases and sales exception and thus were not marked to market and reflected on the balance sheet like other derivatives. Instead, these contracts were previously recorded on an accrual basis.

DIG C15 changed the definition of normal purchases and sales for certain power contracts. DIG C16 disallowed normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. PG&E NEG determined that five of its derivative commodity contracts for the physical delivery of power and purchase of fuel no longer qualified for normal purchases and sales treatment under these interpretations. Beginning April 1, 2002, these five contracts were required to be recorded on the balance sheet at fair value and marked-to-market through earnings. Three of the contracts had positive market values and resulted in pre-tax income of $125 million. The remaining two contracts had negative market values that resulted in a pre-tax charge of $127 million. The cumulative effects of implementation of these accounting changes at April 1, 2002, resulted in PG&E NEG recording price risk management assets of $37 million, price risk management liabilities of $255 million, a reduction of out-of-market obligations of $129 million reclassified to net price risk management liabilities and an increase in investments in unconsolidated affiliates of $87 million.

Implementation of these accounting changes will not impact the timing and amount of cash flows associated with the affected contracts; however, it will impact the timing and magnitude of future earnings. Future earnings will reflect the gradual reversal of the assets and liabilities recorded upon adoption over the contracts’ lives, as well as any prospective changes in the market value of the contracts. The net reversal of these assets and liabilities (using the April 1, 2002 implementation amounts and assuming no market price changes) would provide approximately $44 million of pre-tax net income over the next five years, and a total of $45 million in pre-tax net income thereafter. However, any

prospective changes in the market value of these contracts could result in significant volatility in earnings. Value-at-risk provides a measure of PG&E NEG’s exposure to volatility in future earnings related to the market risk associated with these contracts. PG&E NEG estimates a combined value-at-risk for these contracts of $3.9 million, based on a 95 percent confidence level using a one-day liquidation period. Over the total lives of the contracts, there will be no net impact to total operating results after netting the cumulative effect of adoption against the subsequent years’ impacts (assuming that the affected contracts are held to their expiration).

CRITICAL ACCOUNTING POLICIES

Effective 2001, PG&E NEG adopted SFAS No. 133 which required all financial instruments to be recognized in the financial statements at market value. See further discussion in Price Risk Management Activities above, and Notes 1 and 3 to the Consolidated Financial Statements. PG&E NEG accounts for its energy trading activities in accordance with EITF 98-10 and SFAS No. 133 which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting. EITF 98-10 also allows two methods of recognizing energy trading contracts in the income statement. The “gross” method provides that the contracts are 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. However, as discussed above, beginning in the third quarter of 2002, PG&E NEG will be required under EITF 00-17, to use the net method of presentation.

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 are not reflected on the balance sheet at fair value. See further discussion in “New Accounting Policies” 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 could be recognized in PG&E GTN’s financial statements.

TAXATION MATTERS

The Internal Revenue Service (IRS) has completed its audit of PG&E NEG’s parent, PG&E Corporation’s 1997 and 1998 consolidated U.S. federal income tax returns and has assessed additional federal income taxes of $52.2 million related to PG&E NEG. PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and is currently discussing those adjustments with the IRS’ Appeals Office. The IRS is also auditing PG&E Corporation’s 1999 and 2000 consolidated U.S. federal income tax returns, but has not issued its final report. In addition, PG&E Corporation is utilizing the IRS pre-filing agreement process to seek advanced determinations of a 2001 tax return position with respect to PG&E NEG’s energy tax credits. All of PG&E Corporation’s federal income tax returns prior to 1997 have been closed, including those portions attributable to PG&E NEG.

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

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 is named as a party 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.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

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

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

California Energy Trading Litigation—PG&E Energy Trading Holdings Corporation and various of its affiliates (collectively ET-Power) have been named as defendants, along with other generators and market participants in the California electricity market, in connection with a variety of claims arising out of the California energy crisis. ET-Power has been served with complaints in the following cases. It is possible that it will be served with additional complaints and that all of these cases will be consolidated with other cases in which similar allegations have been raised respecting other market participants. These proceedings are administrative and judicial in nature.

As previously disclosed in PG&E Corporation’s and the Utility’s Annual Report on Form 10-K for the year ended December 31, 2001, ET-Power has been named, along with multiple other defendants, in four class action lawsuits known as Pier 23 against marketers and other unnamed sellers of electricity in California markets. These cases are pending in the U.S. District Court for the Southern District of California. Plaintiffs have a filed motion to remand the proceedings to state court. In addition, the judge has established September 19, 2002, as the deadline for filing motions to dismiss the plaintiffs’ complaint. The hearing on the motion to remand is also set for September 19, 2002.

On May 13, 2002, ET-Power was named, along with multiple other defendants, in a complaint filed by James A. Millar, individually and on behalf of the general public and as a representative taxpayer against energy suppliers and other unnamed sellers of electricity in the California market, in San Francisco Superior Court. In his complaint, plaintiff asserts the defendants violated state laws against unfair and fraudulent business practices by entering into certain long-term energy contracts with the California Department of Water Resources (DWR). The plaintiff claims that the contracts were made under circumstances that resulted in excessively high and unfair prices and, as a result, refunds should be made to the extent that the prices in the contracts were excessive. In addition, plaintiff seeks, among other remedies, an order adjoining enforcement of the allegedly unfair terms and conditions of the long-term contracts, declaratory relief, and attorneys’ fees. The FERC is currently addressing the DWR contracts in the administrative actions before the FERC brought by the CPUC and California Electricity Oversight Board on February 25, 2002. On June 13, 2002 the defendants removed the case to the U.S. District Court for the Northern District of California based on federal preemption. Plaintiffs filed a motion to remand the case to state court. On July 12, 2002, the Judicial Panel on Multidistrict Litigation entered a conditional order transferring this case to the Southern District of California. The panel determined that the Millar case, as well as seven other pending lawsuits, involved common questions of law and fact. ET-Power is currently not a defendant in any of these other lawsuits.

On July 15, 2002, ET-Power was named among other sellers of power in an action filed by the Public Utility District No. 1 of Snohomish County, Public Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, et al., in the U.S. District Court for the Central District of California. Plaintiff alleges various theories of manipulation of the deregulated California electricity market by the defendants in violation of state antitrust laws and state laws against unlawful and fraudulent business practices. Plaintiff claims that the defendants manipulated the energy market, resulting in higher electricity prices and seeks, among other remedies, disgorgement, restitution, injunctive relief, and treble damages. Plaintiff also claims that defendants failed to file their rates in advance with the FERC, which failure plaintiff asserts was a violation of the Federal Power Act.

By letter dated May 7, 2002, ET-Power was advised by the Attorney General of California that it believes ET-Power (along with numerous other generators and market participants) violated state laws governing unfair and fraudulent business practices and that unless ET-Power settled the matter the California Attorney General would by June 1, 2002, file suit against ET-Power. The California Attorney General stated that he will claim that ET-Power failed to have its rates on file with FERC and that accordingly any sales made under such rates violated the Federal Power Act (a claim that the California Attorney General has made before FERC and which FERC has rejected) and that ET-Power exercised market power in charging unjust and unreasonable prices. ET-Power has not yet been served with a complaint in this matter.

In addition to these judicial proceedings, on March 20, 2002, the California Attorney General filed a complaint at the FERC against ET-Power and other named and unnamed public utility sellers of energy and ancillary services. The California Attorney General alleges that wholesale sellers of energy to the California ISO, PX and the DWR 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 the FERC has not been able to determine whether the rates charged by such sellers are just and reasonable; that the FERC’s reporting requirements are insufficient to provide the FERC the information necessary to make this determination and that even if the 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 DWR 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 FERC should declare that market-based rates are not subject to the filed rate doctrine; and (5) the FERC should institute proceedings to determine whether any further relief would be appropriate. On May 31, 2002, the FERC issued a decision denying most of the relief requested and on July 1, 2002, the California Attorney General filed a petition with the FERC seeking rehearing of its order, which petition is now pending.

PG&E NEG believes that the outcome of these matters will not have a material adverse affect on PG&E NEG’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 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. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until EPA issues a draft Clean Water Act NPDES permit for Brayton Point. EPA issued the draft NPDES permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing the matter until he reviews USGenNE’s response to the draft permit. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse affect on PG&E NEG’s financial condition or results of operations.

Natural Gas Royalties Litigation—For information regarding this matter, please see Note 5 of the Notes to the Consolidated Financial Statements.

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 environmental 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. 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. A hearing on the merits of the case is scheduled for August 30, 2002. 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). This litigation was successfully resolved and construction of the pipeline is proceeding.

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.

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

(a) Exhibits:

10.1 Amended and Restated Option Agreement, dated as of June 25, 2002, by and among PG&E National Energy Group, Inc., PG&E Corporation, as borrower, PG&E National Energy Group, LLC and GPSF, Inc. and LBI Group, Inc. (Incorporated by reference to Current Report on Form 8-K filed June 26, 2002 by PG&E Corporation, Exhibit 99.7)

10.2 Amended and Restated Stock Pledge Agreement, dated as of June 25, 2002 by and among PG&E Corporation, as Pledgor, PG&E National Energy Group, LLC, as Issuer, Lehman Commercial Paper Inc., as Administrative Agent and Deutsche Bank Trust Company Americas, as Collateral Agent for the benefit of the Lenders as Pledgee. (Incorporated by reference to Current Report on Form 8-K filed June 26, 2002 by PG&E Corporation, Exhibit 99.6)

10.3 Amended and Restated Stock Pledge Agreement, dated as of June 25, 2002 by and among PG&E National Energy Group, LLC, as Pledgor, PG&E National Energy Group, Inc., as Issuer and Lehman Commercial Paper Inc., as Administrative Agent and Deutsche Bank Trust Company Americas, as Collateral Agent for the benefit of the Lenders as Pledgee. (Incorporated by reference to Current Report on Form 8-K filed June 26, 2002 by PG&E Corporation, Exhibit 99.5)

99.5 Certification of Thomas G. Boren, President and Chief Executive Officer, pursuant to 18 U.S.C. Section 1350

99.6 Certification of Thomas E. Legro, Vice President, Controller and Chief Accounting Officer pursuant to 18 U.S.C. Section 1350

(b) The following Current Reports on Form 8-K were filed during the first two quarters 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

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: August 2, 2002	By:	/s/ Thomas G. Boren
		Thomas G. Boren
		President and Chief Executive Officer

Dated: August 2, 2002	By:	/s/ Thomas E. Legro
		Thomas E. Legro
		Vice President, Controller and
		Chief Accounting Officer


[X]		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

		For the quarterly period ended June 30, 2002

		OR

[ ]		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from ______to ______

(1)		Gross credit exposure equals fair value (adjusted for appropriate credit reserves), net (payables) receivables where netting is allowed.

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

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

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

	(3)		As revised, See Note 1.

			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 to which PG&E NEG’s development plans and strategies are affected by changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others;

	•		Future sales levels which are affected by general economic and financial market conditions, changes in interest rates, weather, conservation efforts, and outages, among other factors;

	•		Whether market conditions will require further impairment or write-off of PG&E NEG assets, which may cause PG&E NEG to fail to comply with the net worth requirements of its loan agreements;

	•		The extent to which PG&E NEG’s current or planned construction 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 construction 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 and the potential loss of permits or other rights in connection with PG&E NEG’s decision to delay or defer construction;

	•		PG&E NEG’s ability to obtain financing from third parties or from PG&E Corporation while preserving PG&E NEG’s credit quality; which ability could be negatively affected by conditions in the general economy or the energy markets or the capital markets, and the market’s perception of the energy industry;

	•		The impact on PG&E NEG of a loss of confidence in the energy industry;

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

	•		The impact of the recent or future downgrades in credit ratings of PG&E NEG and other subsidiaries on PG&E NEG’s and PG&E Corporation’s financial condition which will be affected by the extent to which PG&E NEG and its subsidiaries can meet liquidity calls which may be made in connection with trading activities, meet obligations to fund various equity commitments, provide other collateral to replace PG&E NEG guarantees, or obtain financing for planned development projects, whether PG&E NEG is able to renew a substantial portion of its revolving credit lines otherwise due to expire on August 22, 2002, and whether a default occurs under PG&E Corporation’s credit agreement;

	•		The extent to which counterparties seek damages based upon credit downgrades and their ability to recover such damages;

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

	•		Volatility in income resulting from mark-to-market accounting, changes to mark-to-market methodologies and the extent to which the assumptions underlying PG&E NEG’s mark-to market accounting and risk management programs are not realized;

	•		The effectiveness of PG&E NEG’s risk management policies and procedures ;

	•		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 and changes to rules and tariffs applicable to energy marketing and trading transactions, the markets in which PG&E NEG operates, and the accounting treatment of such transactions;

	•		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 PG&E NEG under certain term loans of PG&E Corporation including requirements for PG&E Corporation to comply with debt covenants regarding cash reserves, loan to value ratios, and investment grade credit ratings, among other;

	•		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;

	•		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 and the City and County of San Francisco 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 outcome of pending litigation and environmental matters.

	•		Forward contracts are commitments to purchase or sell energy commodities in the future;

	•		Futures contracts are standardized commitments to purchase or sell an energy commodity or financial instrument at a specific price and future date;

	•		Swap agreements require payments to or from counterparties for a quantity based upon the difference between agreed upon prices, at least one of which is an index;

	•		Option contracts provide the right to buy or sell the underlying instrument at a specified price;

(1)		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.

(2)		Excludes all non-trading contracts, including non-trading contracts that are recorded at fair value through earnings.

(1)		Includes derivative power and fuels contracts that do not qualify to be accounted for as cash flow hedges or are exempted from SFAS No. 133 as normal purchases and sales.

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

(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.

	(b)		The following Current Reports on Form 8-K were filed during the first two quarters 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