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

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C., 20549

FORM 10-Q

(Mark one)


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

For the quarterly period ended September 30, 2002


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

For the transition period from ______to ______

COMMISSION FILE NO. 333-66032

PG&E National Energy Group, Inc.

(Exact Name of Registrant as Specified in Its Charter)


Delaware	7600 Wisconsin Avenue	94-3316236




(State or Other Jurisdiction of Incorporation or Organization)	(Mailing address: 7500 Old Georgetown Road)	(I.R.S. Employer Identification Number)




	Bethesda, Maryland 20814




	(301) 280-6800

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

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

Yes [X] No [ ]

PG&E NATIONAL ENERGY GROUP, INC.

FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2002
TABLE OF CONTENTS


			Page
PART I. FINANCIAL INFORMATION




ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS			3




		Consolidated Statements of Operations	3




		Consolidated Balance Sheets	4




		Consolidated Statements of Cash Flows	6




	NOTES TO CONSOLIDATED FINANCIAL STATEMENTS		7




		Note 1: General	7




		Note 2: Relationship with PG&E Corporation and the California Electric Industry	14




		Note 3: Liquidity and Financial Resources	15




		Note 4: Price Risk Management	21




		Note 5: Commitments and Contingencies	25




		Note 6: Impairment and Write offs	30




		Note 7: Costs Incurred in an Organizational Restructuring	31




		Note 8: Segment Information	31




		Note 9: Subsequent Events	32




ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			33




		Overview	33




		Market Conditions and Business Environment	37




		Liquidity and Financial Resources	38




		Risk Management Activities	49




		Results of Operations	53




		Critical Accounting Policies	56




		Accounting Pronouncements Issued but Not Yet Adopted	57




		Taxation Matters	58




		Environmental and Legal Matters	58




ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS			59




ITEM 4. CONTROLS AND PROCEDURES			59




PART II. OTHER INFORMATION




ITEM 1. LEGAL PROCEEDINGS			60




ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K			62




SIGNATURES AND CERTIFICATIONS			63

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)


			Three months ended						Nine months ended
			September 30,						September 30,

			2002			2001			2002			2001

Operating Revenues




	Generation, transportation, and trading		$	1,079		$	764		$	2,407		$	2,157




	Equity in earnings of affiliates			8			18			31			67





		Total operating revenues		1,087			782			2,438			2,224





Operating Expenses




	Cost of commodity sales and fuel			763			462			1,638			1,266




	Operations, maintenance, and management			151			126			454			394




	Administrative and general			27			15			51			51




	Impairment and write-offs			125			—			390			—




	Depreciation and amortization			51			45			140			120




	Other operating expenses			20			(2	)		34			47





		Total operating expenses		1,137			646			2,707			1,878





Operating Income (Loss)				(50	)		136			(269	)		346




	Interest income			14			23			46			72




	Interest expense			(54	)		(48	)		(143	)		(106	)




	Other income (expense), net			4			(4	)		1			2





Income (Loss) Before Income Taxes				(86	)		107			(365	)		314




	Income taxes provision (benefit)			(68	)		30			(204	)		112





Net Income (Loss) Before Cumulative Effect Of A Change In Accounting Principle				(18	)		77			(161	)		202




Cumulative Effect Of A Change In Accounting Principle, net of applicable income tax benefit of $42 million				—			—			(61	)		—





Net Income (Loss)			$	(18	)	$	77		$	(222	)	$	202

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

				September 30,			December 31,
				2002			2001

ASSETS




Current Assets




	Cash and cash equivalents			$	371		$	725




	Restricted cash				210			141




	Accounts receivable:




		Trade, net of allowance for uncollectibles of $44 million and $43 million, respectively			1,385			1,031




		Related parties			33			40




	Other receivables				32			54




	Inventory				183			125




	Price risk management				615			427




	Prepaid expenses and other				347			67

			Total current assets		3,176			2,610

Property, Plant and Equipment




	Electric generating facilities				2,878			2,735




	Gas transmission assets				1,611			1,512




	Land				133			131




	Other				185			163




	Construction work in progress				2,712			2,076

		Total property, plant and equipment (at original cost)			7,519			6,617




	Accumulated depreciation				(997	)		(887	)

		Net property, plant and equipment			6,522			5,730

Other Noncurrent Assets




	Long-term receivables				469			455




	Long-term receivables from PG&E Corporation				—			174




	Investments in unconsolidated affiliates				383			414




	Goodwill, net of accumulated amortization at December 31 of $30 million				—			95




	Intangible assets, net of accumulated amortization of $59 million and $47 million, respectively				74			85




	Deferred financing costs, net of accumulated amortization of $59 million and $30 million, respectively				95			103




	Price risk management				550			299




	Other				165			333

		Total other noncurrent assets			1,736			1,958

TOTAL ASSETS				$	11,434		$	10,298

PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS
(in millions)


				Balance at

				September 30,			December 31,
				2002			2001

LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY




Current Liabilities




	Short-term borrowings			$	431		$	330




	Long-term debt, classified as current				773			48




	Obligations due PG&E Corporation				—			309




	Accounts payable:




		Trade			1,252			957




		Related parties			32			41




	Accrued expenses				362			336




	Price risk management				741			293




	Out-of-market contractual obligations				91			116




	Other				78			48

			Total current liabilities		3,760			2,478

Noncurrent Liabilities




	Long-term debt				3,292			3,374




	Deferred income taxes				473			681




	Price risk management				836			312




	Out-of-market contractual obligations				521			683




	Long-term advances from PG&E Corporation				327			118




	Other noncurrent liabilities and deferred credits				95			65

			Total noncurrent liabilities		5,544			5,233

Minority Interest					18			20




Commitments and Contingencies




	(Note 1,3,5)				—			—




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				(832	)		(610	)




	Accumulated other comprehensive income (loss)				(200	)		33

			Total common stockholders’ equity		2,054			2,509

TOTAL LIABILITIES AND COMMON STOCKHOLDERS’ EQUITY				$	11,434		$	10,298

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)


				Nine months ended
				September 30,

				2002			2001

Cash Flows From Operating Activities




	Net income (loss)			$	(222	)	$	202




	Adjustments to reconcile net income to net cash (used in) provided by operating activities:




		Depreciation and amortization			140			120




		Deferred income taxes			(226	)		(77	)




		Price risk management assets and liabilities, net			158			34




		Amortization of out-of-market contractual obligation			(59	)		(107	)




		Other deferred credits and noncurrent liabilities			16			(6	)




		Impairment and write offs			390			—




		Equity in earnings of affiliates			(31	)		(67	)




		Distributions from affiliates			30			49




		Cumulative effect of a change in accounting principle			61			—




	Net effect of changes in operating assets and liabilities:




		Restricted cash			(69	)		(73	)




		Accounts receivable			(233	)		1,256




		Inventories, prepaids and deposits			(281	)		200




		Accounts payable and accrued liabilities			263			(1,212	)




		Accounts payable—related parties, net			(2	)		5




	Other, net				42			(8	)

			Net cash (used in) provided by operating activities		(23	)		316

Cash Flows From Investing Activities




	Capital expenditures				(1,328	)		(1,059	)




	Proceeds from sale leaseback				340			—




	Long-term prepayment on turbines				—			(144	)




	Investment in Southaven project				(74	)		—




	Repayment of note receivable from PG&E Corporation				75			—




	Other, net				30			57

			Net cash used in investing activities		(957	)		(1,146	)

Cash Flows From Financing Activities




	Net borrowings (repayment) under credit facilities				101			(200	)




	Repayment of obligations due related parties and affiliates				(100	)		—




	Long-term debt issued				1,002			703




	Notes issuance, net of discount and issuance costs				—			972




	Long-term debt matured, redeemed, or repurchased				(358	)		(638	)




	Deferred financing costs				(19	)		(19	)

			Net cash provided by financing activities		626			818

Net change in cash and cash equivalents					(354	)		(12	)




Cash and cash equivalents at January 1					725			738

Cash and cash equivalents at September 30				$	371		$	726

Supplemental disclosures of cash flow information




	Cash paid for:




		Interest paid		$	229		$	118




		Income taxes paid, (refunded), net			(91	)		(8	)




Supplemental disclosures of noncash investing and financing




	Reclassification of short-term parent receivable to long-term				—			153




	Non-cash impact of DIG C15 and DIG C16:




		Deferred income taxes			(43	)		—




		Out-of-market contractual obligation			(129	)		—




		Change in equity investment			14			—




		Price risk management assets and liabilities, net			219			—




	Reclassification of demand notes payable to PG&E Corporation from short-term to long-term				209			118




	Change in other comprehensive (income) loss due to No. SFAS 133, net of deferred taxes				234			65




	Change in equity investment due to SFAS No. 133, net of deferred taxes				11			(23	)




	Long-term debt related to a subsidiary				—			(40	)

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. 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.

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 and audited Consolidated Financial Statements have been reclassified to conform to the 2002 presentation. All significant inter-company transactions have been eliminated from the unaudited consolidated financial statements. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

This quarterly report should be read in conjunction with PG&E NEG’s Consolidated Financial Statements and Notes to Consolidated Financial Statements included in its 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.

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

PG&E NEG’s efforts to reduce debt or raise cash through various efforts, including asset sales, have failed to produce adequate sources of liquidity for PG&E NEG to meet its obligations. PG&E NEG, therefore, has been in active negotiations regarding a global restructuring of its debt with the lenders under the Corporate Revolver, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities and the Turbine Revolver as well as representatives of the holders of the Senior Notes. This global restructuring would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG’s merchant assets and reduce energy trading operations. If agreed to by PG&E NEG’s lenders and implemented by PG&E NEG, these various assets transfers, sales and abandonments would cause substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

If the restructuring cannot be achieved by agreement with PG&E NEG’s creditors, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into Chapter 11 of the Bankruptcy Code. Notwithstanding the restructuring efforts above, if PG&E NEG abandons, sells or transfers assets in an effort to meet current liquidity needs or other strategic efforts, PG&E NEG would incur substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

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 provisions 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 be as follows (in millions):


	Three months ended					Nine Months ended
	September 30,					September 30,

	2002			2001		2002			2001

Net Income (loss):




As reported	$	(18	)	$	77	$	(222	)	$	202




Pro-forma		(20	)		75		(227	)		196

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,” as amended by SFAS No. 138, “Accounting for Certain Derivative Instruments and Certain Hedging Activities” (collectively, SFAS No. 133) (in millions):


	2002			2001

Three months ended September 30




Net income (loss)	$	(18	)	$	77




Net gain (loss) in other comprehensive income (OCI) from current period hedging transactions and price changes in accordance with SFAS No 133		(153	)		20




Net reclassification from OCI to earnings		(2	)		3

Comprehensive income (loss)	$	(173	)	$	100

Nine months ended September 30




Net income (loss)	$	(222	)	$	202




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		(237	)		176




Net reclassification from OCI to earnings		3			115

Comprehensive income (loss)	$	(456	)	$	160

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

Change from Gross to Net Method of Reporting Revenues and Expenses on Trading Activities – For the quarter ended September 30, 2002, PG&E NEG changed its method of reporting gains and losses associated with energy trading contracts from the gross method of presentation to the net method. As with the gross method, the net method is in accordance with Generally Accepted Accounting Principles (GAAP). PG&E NEG believes that the net method provides a more accurate and consistent presentation of energy trading activities on the financial statements, in that net presentation is a better method of conveying the changes in market prices associated with trading activities. Amounts to be presented under the net method include all gross margin elements related to energy trading activities, including both unrealized and realized trades and both physical and financial trades.

Before implementation of the net method, PG&E NEG had already reported unrealized gains and losses on trading activities on a net basis in operating revenues. However, PG&E NEG had reported realized gains and losses on a gross basis in operating income, as both operating revenues and costs of commodity sales and fuel. PG&E NEG is now reporting all gains and losses from trading activities, including amounts that are realized, on a net basis as operating revenues. This will provide greater consistency in reporting the results of all energy trading activities. Amounts for trading activities in comparative prior periods have been reclassified to conform to the net method.

Implementation of the net method has no net effect on gross margin, operating income or net income. The net method does not apply to non-trading activities. Accordingly, PG&E NEG continues to report realized income from non-trading activities on a gross basis in operating revenues and in operating expenses. The schedule below summarizes the amounts impacted by the change in methodology on PG&E NEG’s Consolidated Statements of Operations (in millions):


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

		Three months		Nine months		Three months		Nine months
		Ended		Ended		Ended		Ended
		September 30,		September 30,		September 30,		September 30,
		2002		2002		2002		2002

Generation, transportation, and trading revenues		$	4,853	$	10,238	$	1,079	$	2,407




Cost of commodity sales and fuel			4,537		9,469		763		1,638

	Net Subtotal	$	316	$	769	$	316	$	769


	Three months		Nine months		Three months		Nine months
	Ended		Ended		Ended		Ended
	September 30,		September 30,		September 30,		September 30,
	2001		2001		2001		2001

Generation, transportation, and trading revenues	$	3,343	$	10,253	$	764	$	2,157




Cost of commodity sales and fuel		3,041		9,362		462		1,266

Net Subtotal	$	302	$	891	$	302	$	891

Rescission of EITF 98-10 — In October 2002, the Emerging Issues Task Force (EITF) rescinded EITF 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). Energy trading contracts that are derivatives in accordance with SFAS No. 133 will continue to qualify for fair value accounting under SFAS No. 133. Contracts that had been marked to market under EITF 98-10 that do not meet the definition of a derivative will be recorded on a cost basis with a one-time adjustment to be recorded as a cumulative effect of a change in accounting principle as of January 1, 2003.

The EITF also delayed the implementation (to January 1, 2003) of EITF 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities’ and EITF 00-17, ‘Measuring the Fair Value of Energy Related Contracts in Applying EITF 98-10’” (EITF 02-03). The official guidance related to EITF 02-03 will be outlined in the final minutes of the recent EITF meeting, scheduled for release in November 2002.

The reporting requirements associated with the rescission of EITF 98-10 should be applied prospectively for all EITF 98-10 energy trading contracts entered into after October 24, 2002. For all EITF 98-10 energy trading contracts in existence at or prior to October 24, 2002, the effective date is the fiscal quarter beginning after December 15, 2002. PG&E NEG is currently assessing the impact of this ruling.

Change in Estimate Due to Changes in Certain Fair Value Assumptions - PG&E NEG estimates the gross mark-to-market value of its trading contracts and certain non-trading contracts using forward curves. The forward curves used to calculate mark-to-market value have liquid periods (includes continuous maturities starting from the month for which broker quotes are available on a daily basis) and illiquid periods (includes those maturities for which broker quotes are not readily available). When market data is not available, PG&E NEG historically has utilized alternative pricing methodologies, including third-party pricing curves, the extrapolation of forward pricing curves using historically reported data, and interpolating between existing data points. The gross mark-to-market valuation is then adjusted for time value of money, creditworthiness of contractual counterparties, market liquidity in future periods, and other adjustments necessary to estimate fair value. For trading activities, these models are used to estimate the fair value of long-term transactions including qualifying tolling agreements. For non-trading activities, these models are used to estimate the fair value of cash flow hedges, certain power purchase agreements and fuel purchase agreements which are accounted for as derivative contracts under SFAS No. 133.

Beginning in the third quarter of 2002, PG&E NEG implemented a new model for projecting forward power and gas prices during illiquid periods. This new process primarily impacts the estimation of power prices. The model estimates forward power prices in illiquid periods using the mid-point of the marginal cost curve (lowest variable cost of generation available in a particular region) and the forecast curve (price at which a generation unit will recover its capital costs and a return on investment). Assumptions about cost recovery are combined with assumptions about volatility and correlation in an option model to project forward power prices. Interpolation methods continue to be used for intermediate periods when broker quotes are intermittent. In addition to implementing the new process for projecting forward prices in illiquid periods, PG&E NEG also enhanced its models to better incorporate certain physical characteristics of its power plants.

As discussed above, PG&E NEG makes adjustments to gross mark-to-market values to arrive at fair values. Beginning in the third quarter of 2002, PG&E NEG enhanced its process of estimating fair values by adjusting certain long-term valuations to account for uncertainties surrounding projected forward prices, volumetric assumptions and modeling complexity. PG&E NEG also refined its process for estimating the bid-ask spread in illiquid periods for purposes of liquidity adjustments.

All of these changes in fair values are being accounted for on a prospective basis as a change in accounting estimate. These changes in fair values had a pre-tax income effect of a $14 million loss from trading activities and a pre-tax gain of $25 million from non-trading activities. These income effects, totaling a pre-tax gain of $11 million for both trading and non-trading activities, were recognized in the quarter ended September 30, 2002.

Accounting for gains and losses on debt extinguishment and certain lease modifications-On July 1, 2002, PG&E NEG adopted 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 accompanying Consolidated Statements of Operations. 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 criteria for extraordinary classification under GAAP. In addition, SFAS No. 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 provisions did not have any impact on the Consolidated Financial Statements of PG&E NEG at the date of adoption.

Changes to Accounting for Certain Derivative Contracts-On April 1, 2002, PG&E NEG implemented two interpretations issued by the FASB Derivatives Implementation Group (DIG). DIG Issues C15 and C16 changed the definition of normal purchases and sales included in 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 DIG 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 DIG 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, 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).

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 Statement also requires that all long-lived assets to be disposed of by sale be 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 No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, and supersedes previous guidance for discontinued operations of business segments. The adoption of this Statement did not have any impact on the Consolidated Financial Statements of PG&E NEG (See Note 6, Impairment and Write Offs).

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 nine months ended September 30, 2001 was $1 million and $4 million, respectively (See Note 6, Impairment and Write Offs).

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 other than goodwill 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

	September 30, 2002				December 31, 2001

	Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amount		Amortization		Amount		Amortization

Service agreements	$	33	$	7	$	33	$	6
Power sale agreements		67		37		67		30
Other agreements		33		15		32		11

Total		$133	$	59	$	132	$	47

Amortization expense on intangible assets for the three and nine months ended September 30, 2002 was $2 million and $5 million, respectively, compared to $1 million and $3 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. For the nine months ended September 30, 2002 the amount of amortization that was recorded against the related revenue or expense was $7 million.

The following schedule shows the estimated amortization expense, excluding the amortization recorded against the related revenue or expense on power sale agreements, for intangible assets for the full years 2002 through 2006 (in millions):


2002	2003		2004		2005		2006

$6	$	6	$	6	$	6	$	6

Related Party Transactions

As of September 30, 2002 and December 31, 2001, PG&E Corporation had issued a $10 million and $16 million, respectively 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; and a $4 million guarantee related to PG&E Energy Services’ acquisition of the stock of a consulting company prior to PG&E NEG’s sale of PG&E Energy Services.

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

Sheets, as of September 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 September 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.

PG&E ET enters into transactions with 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 nine months ended September 30, 2002 and 2001, PG&E ET had energy commodity sales of approximately $34 million and $109 million, respectively, to the Utility, and energy commodity purchases of approximately $8 million and $19 million, respectively. As of September 30, 2002, PG&E ET had trade receivables relating to energy commodity transactions from the Utility of $24 million, and trade payables relating to energy commodity transactions to the Utility of $1 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 nine months ended September 30, 2002 and 2001, the Utility accounted for approximately $33 million and $29 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 an allocation 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 nine months ended September 30, 2002 and 2001, allocated costs totaled $17 million and $19 million, respectively. The total amount due PG&E Corporation for these services and direct assignment of costs at September 30, 2002, was $8 million.

In addition, PG&E NEG bills PG&E Corporation and the Utility for certain shared costs. For the nine months ended September 30, 2002 and 2001, the total charges billed to PG&E Corporation were immaterial. For the nine months ended September 30, 2002, the total charges billed to the Utility were $3 million of which $2 million is a current receivable. Amounts charged to the Utility for the nine months ended September 30, 2001, were immaterial.

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

For periods before 2001, PG&E Corporation provided financial support in the form of loans to PG&E NEG, and the 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 National Energy Group, Inc., 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 National Energy Group Inc.’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 National Energy Group Inc. meets specified financial requirements.

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. This appeal is still pending.

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. 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, two guarantees of PG&E NEG’s indemnification obligations to purchasers of PG&E NEG’s assets and a guarantee related to PG&E NEG’s obligations to the sellers of assets purchased by PG&E NEG) with a combination of guarantees provided by PG&E NEG or its subsidiaries and letters of credit obtained independently by PG&E NEG. The $16 million office lease guarantee was reduced to $10 million as of September 30, 2002.

NOTE 3: LIQUIDITY & FINANCING RESOURCES

As previously reported in PG&E NEG’s recent filings on Form 8-K with the SEC, before July 31, 2002, most of the various debt instruments of PG&E NEG and its affiliates carried investment-grade credit ratings as assigned by Standard & Poor’s (S&P) and Moody’s Investors Service (Moody’s), two major credit rating agencies. On July 31, 2002 and August 5, 2002, S&P and Moody’s, respectively, downgraded PG&E NEG’s credit ratings, as previously reported. On October 8, 2002, October 16, 2002 and October 18, 2002, Moody’s further downgraded the senior unsecured debt rating, issuer rating and syndicated bank credit facilities of PG&E NEG. On October 11, 2002, S&P further downgraded certain of PG&E NEG’s debt facilities. The result of these downgrades has left all of PG&E NEG rated entities and debt instruments at below investment-grade. The following table shows the credit ratings of the various debt instruments of PG&E NEG and its affiliates, as well as credit ratings assigned for general creditworthiness of individual entities, updated for the most recent issued ratings.


	Standard	Moody's
	& Poor's	Investors Service

*Rated entities:*




PG&E NEG	B-	B3




PG&E GTN	BB-	Ba1




PG&E ET	B-	Not Rated




PG&E Gen	B-	Not Rated




USGenNE	B-	B2




*Rated debt instruments:*




Senior Unsecured Notes, due 2011 (PG&E NEG)	B-	B3




Senior Unsecured Notes, due 2005 (PG&E GTN)	BB-	Ba1




Senior Unsecured Debentures, due 2025 (PG&E GTN)	BB-	Ba1




Senior Unsecured Notes, due 2012 (PG&E GTN)	BB-	Ba1




Medium Term Notes (nonrecourse) PG&E GTN	BB-	Ba1




Term Loan (GenHoldings I, LLC)	CC	B3

Both S&P and Moody’s credit ratings assigned to PG&E NEG and its affiliates are under review for possible further downgrade.

The downgrade of PG&E NEG’s credit ratings impacts various 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” and are generally linked to one or more investment grade ratings. When a downgrade event activates a contractual “ratings trigger,” PG&E NEG’s counterparties may demand that PG&E NEG provide additional security for performance in the form of cash, letters of credit, acceptable replacement guarantees or advanced funding of obligations. If PG&E NEG fails to provide this additional collateral within defined cure periods, PG&E NEG may be in default under contractual terms. In addition to agreements containing ratings triggers, other agreements allow counterparties to seek additional security for performance whenever such counterparty becomes concerned about PG&E NEG’s or its subsidiaries’ creditworthiness.

In addition to various requirements to post additional collateral as described above, PG&E NEG’s credit downgrades constrain its access to additional capital and trigger increases in the cost of indebtedness under many of its outstanding debt arrangements.

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

Short-Term Borrowings and Long-Term Debt

The schedule below summarizes PG&E NEG’s outstanding short-term borrowings and long-term debt as of September 30, 2002 and December 31, 2001 (in millions):


					Outstanding Balance of

			Interest		September 30,		December 31,
Description	Maturity		Rates		2002		2001

PG&E NEG Senior Unsecured Notes		2011		10.375%	$	1,000	$	1,000




PG&E NEG Credit Facility-Tranche B (364 day)		11/14/02		LIBOR plus credit spread		431		330




Turbine and Equipment Facility		12/31/03		LIBOR plus credit spread		205		221

PG&E GTN Senior Unsecured Notes		2005		7.10%		250		250




PG&E GTN Senior Unsecured Debentures		2025		7.80%		150		150




PG&E GTN Senior Unsecured Notes		2012		6.62%		100		—




PG&E GTN Medium Term Notes	Thru 2003			6.83% to 6.96%		6		39




PG&E GTN Credit Facility		5/2/05		LIBOR plus credit spread		—		84

GenHoldings Construction Facility		12/21/06		LIBOR plus credit spread		1,025		450




LaPaloma Construction Facility		3/7/05		LIBOR plus credit spread		646		588




Lake Road Construction Facility		8/28/04		LIBOR plus credit spread		446		417




USGenNE Credit Facility		9/1/03		LIBOR plus credit spread		75		75




Plains End Construction Facility		9/6/06		LIBOR plus credit spread		44		23

Other non-recourse project term loans		Various		Principally LIBOR plus credit spread		94		100




Mortgage loan payable		2010		CP rate + 6.07%		7		8




Other		Various		Various		17		17

Total Short-term borrowings and Long-term debt					$	4,496	$	3,752

Amount classified as Short-term borrowings					$	431	$	330




Long-term debt, classified as current						773		48




Long-term debt						3,292		3,374

Total Short-term borrowings and Long-term debt					$	4,496	$	3,752

Interest is capitalized as a component of projects under construction. For the nine months ended September 30, 2002 and 2001, PG&E NEG capitalized interest of approximately $141 million and $87 million, respectively.

As of September 30, 2002, scheduled maturities of long-term debt were as follows (in millions):


Three months ended December 31, 2002		$	27




Three months ended March 31, 2003			604




Three months ended June 30, 2003			27




Three months ended September 30, 2003			115




Three months ended December 31, 2003			105




2004			24




2005			51




2006			297




2007			1,018




Thereafter			1,797

	Total Long-term debt	$	4,065




	Short-term borrowings		431

	Total Short-term borrowings and Long-term debt	$	4,496

Through August 22, 2002, PG&E NEG had a $1.25 billion working capital and letter of credit facility consisting of $750 million with a 364-day term and $500 million with a two-year term. The $750 million 364-day revolving credit facility was scheduled to expire and be renewed on August 22, 2002. On August 22, 2002, PG&E NEG and the lenders under the revolving credit facilities entered into an amendment to the credit facilities which extended the expiration and renewal date of the 364-day facility to October 21, 2002, and reduced the available commitments under that facility to $500 million. As of September 30, 2002, $431 million had been drawn against the 364-day revolving credit facility and $277 million of letters of credit had been issued against the two-year facility.

On October 21, 2002, PG&E NEG and the lenders under the 364-day and two-year revolving credit facilities entered into a further amendment to the credit facilities, which extended the expiration and renewal date to November 14, 2002. The amendment (1) reduces the lenders’ commitments under the 364-day facility and the two-year facility to $431 million and $273 million, respectively, which are the amounts outstanding as of October 21, 2002; (2) prohibits PG&E NEG from making any payment for the Athens, Covert, Harquahala and La Paloma generating projects under construction; and (3) changes the interest payment schedule from quarterly to monthly. PG&E NEG does not expect to repay the 364-day tranche on November 14, 2002, nor does PG&E NEG expect a further extension of the maturity date.

PG&E NEG also has other revolving credit facilities held by subsidiaries, including a $125 million facility held by PG&E GTN, a $100 million facility held by USGenNE, and a $205 million equipment revolving credit facility held by PG&E NEG Construction Company. These facilities relate specifically to funding requirements of these entities and are not available to PG&E NEG. Under the terms of the various revolving credit facilities, the credit spread component of the interest rates and fees charged for borrowings was increased as a result of PG&E NEG’s credit downgrades. PG&E NEG’s credit downgrades through October 18, 2002 did not trigger any acceleration of payments due under its long-term debt arrangements.

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 that as a result of the downgrades has increased to 1.45 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 September 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.

On April 5, 2002, GenHoldings I, LLC, (GenHoldings) an indirect subsidiary of PG&E NEG, increased its committed financing from $1.075 billion to $1.460 billion. At September 30, 2002, the outstanding balance under this facility was $1.025 billion. The increase in the facility was intended to provide for additional borrowing capacity for, and be secured by, an additional project, Covert, which is currently under construction.

PG&E NEG’s efforts to reduce debt or raise cash through various efforts, including asset sales, have failed to produce adequate sources of liquidity for PG&E NEG to meet its obligations. PG&E NEG, therefore, has been in active negotiations with the lenders under the Corporate Revolver, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities and the Equipment Revolver as well as representatives of the holders of the Senior Notes. PG&E NEG has proposed a global restructuring of these debt facilities which would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG’s merchant assets and reduce energy trading operations. If agreed to by PG&E NEG’s lenders and implemented by PG&E NEG, these various asset transfers, sales and abandonments would cause substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

If the restructuring cannot be achieved by agreement with PG&E NEG’s creditors, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into Chapter 11 of the Bankruptcy Code. Notwithstanding the restructuring efforts above, if PG&E NEG abandons, sells or transfers assets in an effort to meet current liquidity needs or other strategic efforts, PG&E NEG could incur substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

Letters of Credit

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


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

PG&E NEG		8/03⁽¹⁾	$	279	$	277




USGenNE		8/03	$	25	$	15




PG&E Gen		12/04	$	10	$	7




PG&E ET		12/02	$	25	$	24




PG&E ET		—⁽²⁾	$	50	$	49




PG&E ET		11/03	$	35	$	34

(1)		On October 21, 2002, PG&E NEG and the lenders under the two-year revolving credit facility entered into an amendment which reduces the lenders commitments to $273 million which is the amount outstanding at October 21, 2002.




(2)		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 obligations. There is no term for the facility, but the bank can review for termination each year.

Construction-Related Equity Commitments

GenHoldings Equity Commitment- Under the GenHoldings credit facility, GenHoldings is committed to make equity contributions to fund construction of the Harquahala, Covert and Athens generating projects. This credit facility is secured by these projects in addition to the Millennium generating facility. PG&E NEG has guaranteed GenHoldings’ equity commitment. Due to the downgrade to below investment grade by both S&P and Moody’s, PG&E NEG became required to fund construction draws under the GenHoldings credit facility entirely with equity until GenHoldings’ full equity commitment was fulfilled. After GenHoldings fulfilled its equity commitment, the lenders were to fund construction draws in accordance with the credit facility. In August and September 2002, PG&E NEG funded approximately $150 million of the equity commitments, with the outstanding equity commitment at September 30, 2002 remaining at $355 million. In October 2002, PG&E NEG notified the lenders under the GenHoldings credit facility that it would not make further equity contributions on behalf of GenHoldings. On October 24, 2002, GenHoldings and the lenders under the GenHoldings credit facility entered into a Second Waiver and Forbearance Agreement pursuant to which the lenders waived through November 14, 2002, existing defaults under the GenHoldings credit agreement and permitted GenHoldings to borrow up to $50 million and agreed to issue specified letters of credit in a face amount not to exceed $36 million. On October 25, 2002, the lenders funded GenHoldings pending draw request for the Athens, Covert and Harquahala construction projects. The lenders also agreed to forbear until November 14, 2002, from exercising any remedies with respect to existing defaults. PG&E NEG does not expect an extension to this forbearance.

La Paloma Equity Commitment-PG&E NEG guaranteed the repayment of certain debt representing La Paloma’s equity commitment in the aggregate amount of $379 million which is due in March 2003. Due to the downgrade to below investment grade by both S&P and Moody’s, PG&E NEG, as guarantor, became required to make equity contributions under the La Paloma credit facility to fund construction costs. In October 2002, PG&E NEG funded $4.5 million of construction costs reducing the outstanding equity commitment at October 31, 2002, to $374.5 million. In October 2002, PG&E NEG notified the lenders under the La Paloma credit facility that it would not make further payments of construction costs for La Paloma. On November 8, 2002, PG&E NEG and the La Paloma lenders entered into an agreement pursuant to which, among other things, the lenders funded on November 8, 2002, the pending draw request to pay construction costs. PG&E NEG does not currently expect to have sufficient funds to make the $374.5 million payment in March 2003.

Lake Road Equity Commitment-PG&E NEG guaranteed the repayment of certain debt representing Lake Road’s equity commitment in the aggregate amount of $230 million which is due in March 2003. Lake Road entered commercial operation in May 2002. PG&E NEG does not currently expect to have sufficient funds to make this payment in March 2003.

Activities Related to Merchant Portfolio Operations

PG&E NEG and certain subsidiaries have provided guarantees to approximately 250 counterparties in support of PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio in the face amount of $2.8 billion (including $69 million in guarantees pursuant to pipeline tariff provisions and $89 million in guarantees to power pools which have an aggregate exposure of less than $1 million). 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 September 30, 2002, PG&E NEG and its rated subsidiaries’ aggregate exposure under these guarantees was approximately $200 million, as follows: PG&E NEG $80 million; PG&E GTN $79 million; PG&E ET $39 million; and USGenNE $2 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its various subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.

At September 30, 2002, PG&E ET’s estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $95 million.

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

Tolling Agreements

The face amount of PG&E NEG’s and its subsidiaries’ guarantees relating to PG&E ET’s tolling agreements is approximately $600 million. The five tolling agreements are with (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $176 million; and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

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

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

Calpine- The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement and construction contractor for the Otay Mesa facility. On October 16, 2002 PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002 that it was terminating the tolling agreement effective November 29, 2002. PG&E NEG was required to provide in December 2002, a guarantee of PG&E ET’s payment obligations under a 10-year tolling agreement with Calpine involving the Otay Mesa facility. The guarantee amount was not to exceed $20 million. As a result of the termination of the tolling agreement, PG&E NEG believes it is no longer obligated to provide a guarantee.

Southaven-PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade, as defined in the agreement. The amount of the guarantee now does not exceed $176 million. The original maximum amount of the guarantee was $250 million, but this amount was reduced by approximately $74 million, the amount of a subordinated loan that PG&E ET made to Southaven on August 31, 2002, pursuant to a subordinated loan agreement between PG&E ET and Southaven. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the agreement and because PG&E ET had failed to provide within thirty days from the downgrade, substitute credit support that meets the requirement of the agreement. Under the agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southhaven with a notice of default respecting Southhaven’s performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Caledonia-PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade, as defined in the agreement. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the agreement and because PG&E ET had failed to provide within thirty days from the affiliate’s downgrade, substitute credit support that meets the requirement of the agreement. Under the agreement, Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia’s performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Under each tolling agreement determination of the termination payment is based on a formula that takes into account a number of factors including market conditions such as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as 6 months to more than a year to complete. To the extent that PG&E ET did not pay these damages, the counterparties could seek payment under the guarantees for an aggregate amount not to exceed $600 million. PG&E NEG believes that its exposure under these guarantees will be less than $600 million. PG&E NEG is unable to predict whether counterparties will seek to terminate their tolling agreements. PG&E NEG does not currently expect to be able to pay all of the termination payments if they become due.

Other Guarantees

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

PG&E NEG has issued guarantees for the performance of the contractors building the Harquahala and Covert power projects for up to $555 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. The constructor and various equipment vendors are performing under their underlying contracts. On August 8, 2002, PG&E NEG replaced the ratings triggers contained in $555 million of guarantees for the performance of the contractors building the Harquahala and Covert power projects with financial covenants that are consistent with those contained in PG&E NEG’s revolving credit and other loan facilities.

PG&E NEG has issued $100 million of guarantees to the constructor of the Harquahala and Covert projects to cover certain separate cost–sharing arrangements. Failure to perform under those separate cost-sharing arrangements or the related guarantees would not have an impact on the constructor’s obligations to complete the Harquahala and Covert projects pursuant to the construction contracts. However, in the event that the construction contractor incurs certain unreimbursed project costs or cost overruns, the contractor could assert a claim against PG&E NEG’s subsidiary or PG&E NEG under its guarantees. PG&E NEG believes that no claim can be validly asserted by the construction contractor as of the date hereof.

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. Attala Energy Company is currently experiencing a negative cash flow performing under this agreement and requires cash infusions in order to perform its obligation. PG&E NEG may stop making cash infusions to Attala Energy Company which could cause a default under the Attala sale-lease back financing.

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 has issued guarantees with an aggregate face value of up to approximately $175 million in connection with these equipment commitments. PG&E NEG’s commitment to purchase combustion turbines and related equipment exceeds its current planned development activities. PG&E NEG and its equipment vendors have agreed to suspend any PG&E NEG payment obligations (except for $14 million as of October 31, 2002) for at least the next nine months. The $14 million is due in January and July, 2003. Beginning in September 2003, 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 NEG estimates these termination costs, and its exposure under these guarantees, to be approximately $53 million as of October 31, 2002 (including the $14 million as of October 31, 2002).

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

Other Commitments

PG&E NEG’s subsidiary 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 not occurred. On October 8, 2002, PG&E NEG’s subsidiary suspended all construction activities related to Mantua Creek. As of September 30, 2002, PG&E NEG had recorded assets of $269 million for Mantua Creek, representing equipment payments, construction activities, development costs and gas transmission deposits. If PG&E NEG’s subsidiary terminates construction of this project, its construction contractor and other equipment and service providers would be entitled to termination costs estimated to be $64 million. PG&E NEG’s subsidiary would receive a refund due from its turbine vendor of approximately $31 million. The construction contractor and other equipment and service providers are the beneficiaries of letters of credit issued on behalf of Mantua Creek by PG&E NEG in the amount of approximately $37 million. The termination costs do not include remediation costs estimated to be $1 million.

PG&E NEG’s subsidiary has executed construction contracts for its Smithland and Cannelton projects for up to 163 MW at two hydroelectric facilities on the Ohio River in Kentucky. As of September 30, 2002, PG&E NEG had recorded assets of $1.8 million for these projects, representing equipment payments and development costs. PG&E NEG’s subsidiary had commenced construction of the first 16 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. The reevaluation is complete and the Army Corps of Engineers concurs that the new seismic criteria will not require any design changes. PG&E NEG’s subsidiary has not resumed construction. The construction contractor is the beneficiary of a letter of credit securing PG&E NEG’s subsidiary termination payment obligations. If PG&E NEG’s subsidiary terminates construction of this project, the construction contractor will be entitled to draw on the letter of credit for approximately $7 million.

Material Notices

PG&E NEG and its subsidiaries have received various notices under major contracts (other than the tolling agreements described above) alleging anticipatory breaches of contract and defaults resulting from PG&E NEG’s downgrades and its public statements regarding its decisions not to make certain payments. These notices include claims from at least one counterparty to a power supply agreement. In most cases, PG&E NEG or its subsidiary has disputed these allegations. In all cases, the counterparties have refrained from attempting to pursue remedies. The Shaw Group, Inc. (Shaw) has alleged anticipatory breaches of the construction contracts for each of Covert and Harquahala based upon PG&E NEG’s announcement that it would not further fund the GenHoldings projects, including the Covert and Harquahala projects. Covert and Harquahala have disputed these notices because they are current in their payments to Shaw. Shaw has also sought reinstatement of pre-financing guarantees ($50 million each) originally issued in connection with the Covert and Harquahala projects. PG&E NEG has denied that the guarantees are reinstated because the financing arrangements remain in place. Finally, Shaw has also sought cash collateralization of PG&E NEG’s $100 million of guarantees supporting Shaw’s cost-sharing agreements with a subsidiary. PG&E NEG has reviewed the guarantees and informed Shaw that the guarantees do not contain any collateralization requirement.

Bechtel Power Corporation (BPC) has alleged a default based upon PG&E NEG’s announcement that it would not further fund the GenHoldings projects, including the Athens project. Athens has disputed this notice because the lenders have continued to fund and BPC is the beneficiary of an escrow account covering future costs that is currently over-funded. BPC has also alleged a default for nonpayment at Mantua Creek. Mantua Creek has 30 days to cure this nonfunding. If it does not do so, BPC is the beneficiary of a letter of credit posted on behalf of Mantua Creek which is sufficient to cover such payment.

Mitsubishi Power Systems, Inc. (MPS) has alleged a default under its contract for the sale and purchase of gas turbines and other equipment for failure to pay $14 million. PG&E NEG’s subsidiary has disputed this default notice because the payments are not due until January and July 2003. MPS also requested that PG&E NEG cash collateralize its $75 million guarantee issued in connection with the turbine purchase agreement. PG&E NEG has informed MPS that no such collateral would be delivered. Non-performance under the guaranty is not a default under the turbine purchase agreement.

NOTE 4: 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 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 and ongoing interpretations of the FASB’s DIG. 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 EITF No. 98-10.

Derivatives associated with both trading and non-trading activities include forward contracts, futures, swaps, options, and other contracts.

• A forward contract is a commitment to purchase or sell energy commodities at a specified future date at a specified price.

• A futures contract is a standardized commitment, traded on an organized exchange, to purchase or sell an energy commodity or financial instruments at a specified future date and at a specified price.

• A swap agreement requires payments for a quantity of an energy commodity based upon the difference between agreed upon prices.

• An option contract provides the right, but not the obligation, to buy or sell the underlying commodity at a predetermined price in the future.

Non-Trading Activities

At September 30, 2002, PG&E NEG had cash flow hedges of varying durations associated with price risk, foreign currency risk, 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 or Loss (OCI), net of taxes, at September 30, 2002, was a loss of $4 million. The amount of interest rate hedges included in OCI, net of taxes, at September 30, 2002, was a loss of $192 million. The amount of foreign currency hedges included in OCI, net of taxes, at September 30, 2002, was a loss of $2 million. PG&E NEG’s net derivative losses included in OCI at September 30, 2002, were $198 million, of which net losses of $56 million are expected to be reclassified into earnings within the next twelve 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			Nine Months			Nine Months
	ended			ended			ended			ended
	September 30, 2002			September 30, 2001			September 30, 2002			September 30, 2001

Derivative gains (losses) included in accumulated other comprehensive income (loss) at beginning of period	$	(43	)	$	(65	)	$	36		$	—




Cumulative effect of Adoption of SFAS No. 133		—			—			—			(333	)




Net gain (loss) from current period hedging transactions and price changes		(153	)		20			(237	)		176




Net reclassification to earnings		(2	)		3			3			115

Derivative net losses included in accumulated other comprehensive loss at end of period		(198	)		(42	)		(198	)		(42	)




Foreign currency translation adjustment		(2	)		(3	)		(2	)		(3	)

Accumulated other comprehensive loss at end of period	$	(200	)	$	(45	)	$	(200	)	$	(45	)

For most non-trading activities, earnings are recognized on the accrual basis as revenues are earned and as expenses are incurred. Thus, most non-trading activities do not affect earnings on a mark-to-market basis. For example, the effective portion of contracts accounted for as cash flow hedges have no mark-to-market effect on earnings; these contracts are presented on a mark-to-market basis on the balance sheet in price risk management assets and liabilities and OCI. Other non-trading contracts are exempt from the SFAS No. 133 fair value requirements under the normal purchases and sales exception and thus have no mark-to-market effect on earnings.

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

The effects on pre-tax earnings of non-trading activities that are reflected in income on a mark-to-market basis is as follows (in millions):


	Three months ended					Nine months ended
	September 30,					September 30,

	2002		2001			2002			2001

Ineffective portion of cash flow hedges	$	2	$	(2	)	$	5		$	(2	)




Non-trading derivatives marked-to-market through earnings		4		—			(105	)		—

Total	$	6	$	(2	)	$	(100	)	$	(2	)

Of the $105 million pre-tax loss attributable to non-trading derivatives marked-to-market through earnings for the nine months ended September 30, 2002, a $3 million (pretax) loss is included in the cumulative effect of adoption of DIG C15 and C16, as well as, a $101 million pre-tax impairment charge also recognized in that line item. The remainder of the non-trading mark-to-market effects on earnings are classified in operating income.

Trading Activities

Unrealized gains and losses from trading activities, including the reversal of unrealized gains and losses previously recognized on contracts that go to settlement or delivery, are presented on a net basis in operating revenues. Realized gains and losses from trading activities also are presented on a net basis in operating revenues, beginning in the third quarter of 2002, as more fully described in Note 1. PG&E NEG has reviewed its trading activities for 2001 and for the first five months of 2002 for potential instances of so-called “wash trades,” and determined that identified trades did not in the aggregate have a significant impact on revenues or expenses in any of the quarters in that period.

Gains and losses on trading contracts affect PG&E NEG’s gross margin in the accompanying PG&E NEG unaudited Consolidated Statements of Operations on an unrealized, mark-to-market basis as the fair value of the forward positions on these contracts fluctuate. Settlement or delivery on a contract is generally not an event that results in incremental net income recognition, 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 reported in the table below primarily reflect the net effect of contracts that have been settled in cash. Net realized gains also include certain non-cash items, including amortization of option premiums that were paid or received in cash in earlier periods but are considered realized when the related options are exercised or expire.

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


	Three months ended						Nine months ended
	September 30,						September 30,

	2002			2001			2002			2001

Trading activities:




Unrealized gains and losses, net	$	(27	)	$	(43	)	$	(80	)	$	(29	)




Realized gains, net		84			87			165			195

Total	$	57		$	44		$	85		$	166

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 September 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		$	235	$	288	$	(228	)	$	(285	)	$	10




Non-trading activities




	Cash flow hedges – offset to OCI		356		194		(473	)		(320	)		(243	)




	Derivatives marked to market through earnings		24		68		(40	)		(231	)		(179	)





Total consolidated PRM Assets and Liabilities		$	615	$	550	$	(741	)	$	(836	)	$	(412	)

Non-trading activities include certain long-term contracts that are not included in PG&E NEG’s trading portfolio but that, due to certain pricing provisions and volumetric variability, are unable to receive hedge accounting treatment or the normal purchases and sales exception, as outlined by interpretations of SFAS No. 133. PG&E NEG has certain other non-trading derivative commodity contracts for the physical delivery of purchases and sales quantities transacted in the normal course of business. These other non-trading activities include contracts that are exempt from the requirements of SFAS No. 133 as normal purchases and sales, 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 accounting loss that PG&E NEG would incur if counterparties fail to perform their contractual obligations (net 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, such as investor-owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies, located in the United States and Canada. This concentration of counterparties may impact the overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory, or other conditions. PG&E NEG manages credit risk pursuant to its Risk Management Policies, which provide processes by which counterparties are assigned credit limits in advance of entering into significant exposure. These procedures include an evaluation of a potential counterparty’s financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually. Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E NEG takes immediate action to reduce exposure and/or obtain additional collateral. Further, PG&E NEG relies heavily on master agreements that contain credit support provisions that require the counterparty to post security in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

PG&E NEG calculates gross credit exposure by counterparty as the current mark-to-market value (what would be lost if the counterparty defaulted today) plus or minus any outstanding net receivables or payables, before 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 September 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 September 30, 2002 (in millions):


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

$1,068		$131	$	937

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




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

At September 30, 2002, approximately $200 million or 21 percent of PG&E NEG’s net credit exposure is to entities that have credit ratings below investment-grade. Investment-grade is determined using publicly available information (i.e., rated at least Baa3 by Moody’s and BBB- by S&P). Approximately $86 million or 9 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 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 2001 Annual Report on Form 10-K was filed. See Note 3 for detailed discussion of contingencies.

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 $13 million from the sale over the lease period which is 37 years. The payment obligations under this agreement are as follows (in millions):


2002	$	—




2003		38




2004		28




2005		29




2006		27




2007		29




Thereafter		602

	$	753

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

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 also will be forthcoming as part of these regulatory initiatives. Management believes that USGenNE would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants and estimates that capital expenditures on these environmental projects could approximate $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, the 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 becomes 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 the 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 which was submitted on October 4, 2002. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse effect on PG&E NEG’s financial condition or results of operation.

On April 9, 2002, the EPA proposed regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations would affect existing power generation facilities using over 50 million gallons per day typically including some form of “once-through” cooling. Brayton Point, Salem Harbor, and Manchester Street are among an estimated 539 plants nationwide that would be affected by this rulemaking. The proposed rule calls for a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. The final regulations are scheduled to be promulgated in 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 $6 million in 2000, $2 million in 2001 and $4 million through September 2002. In addition to the costs previously incurred, PG&E NEG maintains a reserve in the amount of $6 million relating to its estimate of the remaining 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, USGenNE, 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.

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

FERC California Refund Proceeding — In a June 19, 2001 order, the FERC required that all public utility sellers and buyers in certain California markets participate in settlement discussions to complete the task of settling past accounts and structuring the new arrangements for California’s future energy markets. PG&E ET-Power is one such seller and buyer. These settlement discussions have been completed and they were not successful. As a result, the administrative law judge presiding over the discussions recommended to the FERC a methodology to be used in connection with evidentiary hearings that are to be undertaken to, among other things, determine a settlement of past accounts. 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 took place this summer before the FERC administrative law judge to determine the refund amounts and additional amounts owed. In addition, on August 21, 2002, the U.S. Court of Appeals for the Ninth Circuit issued an order consolidating the appeals of certain FERC dockets related to this docket and remanded those other proceedings for FERC to take additional evidence of market manipulation by various sellers. 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. Provided that the offsets are permitted, PG&E NEG believes that the ultimate outcome of this matter will not have a material adverse affect on PG&E NEG’s financial condition or results of operations.

Natural Gas Royalties Litigation – This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including PG&E GTN. The cases were consolidated for pretrial purposes in the U.S. District Court, for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998. Under procedures established by the False Claims Act, the United States (acting through the Department of Justice (DOJ)) is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases. The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) mismeasured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases. The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and expenses associated with the litigation. PG&E NEG believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation. PG&E NEG believes that it is reasonably possible that it could incur a loss, but it is not able to determine the amount of such loss and, therefore, whether in light of the recent deterioration of PG&E NEG’s financial condition, such loss would have a material adverse affect on PG&E NEG’s financial condition or results of operations.

Asbestos Litigation - Pursuant to an Asset Purchase Agreement dated as of August 5, 1997, USGenNE agreed to indemnify New England Power Company (NEPCo) for certain losses. Such losses included claims arising from certain conditions on the site of the generation assets USGenNE purchased under the Asset Purchase Agreement. Several parties have filed suit or indicated that they may file suit against NEPCo for damages they claim arose out of exposure to asbestos fibers, which exposure allegedly took place while working at one or more of the generation assets that USGenNE purchased from NEPCo. Under the Asset Purchase Agreement USGenNE may be required to indemnify NEPCo for some or all of these claims. 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 for these costs along with a ruling that under the WSOS Agreements these costs should be imposed on USGenNE going forward. On March 27, 2002, the parties formally commenced arbitration. As of September 30, 2002, NEPCo has incurred approximately $32 million for these power pool costs. It is estimated that going forward costs will be approximately $19 million for the balance of the term of the WSOS Agreements. The WSOS Agreements will expire at the end of 2004 and 2009. Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of this litigation may have a material adverse effect on PG&E NEG’s financial condition or results of operations.

NOTE 6: IMPAIRMENT AND WRITE OFFS

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 in the second quarter of 2002. The remaining asset value (recorded in Other Non Current Assets) that PG&E NEG has retained as of September 30, 2002, for its portfolio of development projects is $49 million. PG&E NEG anticipates continuing to develop these projects to completion or for future disposal. 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 in the second quarter of 2002. 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 terminated its commitments or options with respect to only three turbines and related equipment. The remaining asset value (recorded in Other Non Current Assets) that PG&E NEG has retained as of September 30, 2002, for its investment in turbines and related equipment is approximately $34 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 as of September 30, 2002) for at least the next nine 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.

Goodwill Write off- As described in Note 1, on January 1, 2002, PG&E NEG adopted SFAS No. 142 “Goodwill and Other Intangible Assets.” Upon implementation of this Statement, the transition impairment test was performed as of January 1, 2002, and no impairment loss was recorded. SFAS No 142 requires that goodwill be reviewed at least annually for impairment. Due to significant adverse changes within the national energy markets, PG&E NEG has elected to test its goodwill for possible impairment in the third quarter of 2002. Based upon the results of the fair value test, PG&E NEG recognized a goodwill impairment loss of $95 million on September 30, 2002. The fair value of the segment was estimated using the discounted cash flows method. This charge is included in the impairment and write offs line item on PG&E NEG’s Consolidated Statements of Operations in the three months and nine months ended September 30, 2002.

Impairment of Dispersed Generation Assets- In PG&E NEG’s Dispersed Generation operations, equipment (turbines, generators, transformers, metering equipment etc.) was purchased and or refurbished and held for future expansions at current Dispersed Generation’s facilities. During the third quarter, based on the changes in national energy markets and specifically the markets that Dispersed Generation’s assets operate, PG&E NEG assessed the probability of utilizing these assets for expansion. PG&E NEG measured the estimated capital investment necessary for expansion against the future estimated cash flows to be generated. It was determined that such investments would be uneconomical and that PG&E NEG cannot characterize these expansion projects as probable. The book value of this equipment was approximately $46 million at September 30, 2002. Based on recent market quotes and expected net salvage values, PG&E NEG has recorded an impairment charge of approximately $30 million in the third quarter of 2002. This charge is included in the impairment and write offs line item on PG&E NEG’s Consolidated Statements of Operations in the three months and nine months ended September 30, 2002.

NOTE 7: COSTS INCURRED IN AN ORGANIZATIONAL RESTRUCTURING

In the third quarter of 2002, PG&E NEG initiated a restructuring effort in order to adopt a new organizational structure that more closely reflects PG&E NEG’s business strategies. The termination benefits accrued and charged to earnings in the third quarter were $9.3 million and are principally included in “Administrative and general” in the operating expenses of PG&E NEG’s Consolidated Statements of Operations. There were 178 employees who were effected by this restructuring of which 161 were terminated as of September 30, 2002 (for which $8.5 million of termination benefits were charged against the liability). All employee groups were impacted by this restructuring.

In addition to these termination costs, PG&E NEG accrued and charged to earnings $9.4 million due to the closing of certain regional offices associated with project development and other third party costs related to the organizational restructuring efforts. These costs are included in “Administrative and general” in the operating expenses of PG&E NEG’s Consolidated Statements of Operations in the third quarter of 2002.

NOTE 8: 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, 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.

Segment information for the three and nine months ended September 30, 2002, and 2001 was as follows (in millions):


	Integrated
	Energy and			Interstate
	Marketing			Pipeline		Other and
	Activities			Operations		Eliminations⁽³⁾			Total

Three Months Ended September 30, 2002




Operating revenues⁽¹⁾	$	1,015		$	62	$	2		$	1,079




Intersegment revenues⁽²⁾		7			—		(7	)		—




Equity in earnings of affiliates		8			—		—			8

Total operating revenues		1,030			62		(5	)		1,087




Income (loss) before cumulative effect of a change in accounting principle		(36	)		21		(3	)		(18	)




Net Income (loss)		(36	)		21		(3	)		(18	)




Three Months Ended September 30, 2001




Operating revenues⁽¹⁾	$	706		$	57	$	1		$	764




Intersegment revenues⁽²⁾		9			—		(9	)		—




Equity in earnings of affiliates		18			—		—			18

Total operating revenues		733			57		(8	)		782




Income (loss) before cumulative effect of a change in accounting principle		64			19		(6	)		77




Net Income (loss)		64			19		(6	)		77




Nine Months Ended September 30, 2002




Operating revenues⁽¹⁾	$	2,230		$	175	$	2		$	2,407




Intersegment revenues⁽²⁾		16			—		(16	)		—




Equity in earnings of affiliates		31			—		—			31

Total operating revenues		2,277			175		(14	)		2,438




Income (loss) before cumulative effect of a change in accounting principle		(200	)		56		(17	)		(161	)




Net Income (loss)		(261	)		56		(17	)		(222	)




Nine Months Ended September 30, 2001




Operating revenues⁽¹⁾	$	1,964		$	185	$	8		$	2,157




Intersegment revenues⁽²⁾		11			1		(12	)		—




Equity in earnings of affiliates		67			—		—			67

Total operating revenues		2,042			186		(4	)		2,224




Income (loss) before cumulative effect of a change in accounting principle		152			57		(7	)		202




Net Income (loss)		152			57		(7	)		202




Total assets at September 30, 2002	$	10,004		$	1,318	$	112		$	11,434




Total assets at September 30, 2001	$	8,447		$	1,198	$	140		$	9,785

⁽¹⁾		Operating revenues and operating expenses for the three months and nine months ended September 30, 2002, reflect the adoption of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. The amounts for trading activities for the comparative periods in 2001 have been reclassified to conform with the new net presentation.




⁽²⁾		Inter-segment revenues are recorded at market prices for services provided.




⁽³⁾		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.

NOTE 9: SUBSEQUENT EVENTS

Sale of Interest in Hermiston – On November 4, 2002, affiliates of PG&E NEG entered into an agreement to sell 49.9 percent of its ownership interest in Hermiston Generating Company, L.P. (HGC) to Sumitomo Corporation and Sumitomo Corporation of America. The buyer was granted an option to purchase, during the three month period beginning thirteen months immediately following the closing date, an additional 0.1 percent interest (at the fair market value at the date of exercise). HGC owns an undivided 50 percent interest in a 474 MW gas-fired generating plant in Hermiston, Oregon. The other 50 percent is owned by PacifiCorp who also purchases the output of the plant under a long-term contract. The sale is expected to be completed by December 31, 2002, following the receipt of necessary regulatory approvals. At September 30, 2002, book value of PG&E NEG’s investment in HGC was approximately $44 million. PG&E NEG anticipates a pre-tax gain of approximately $23 million upon completion of the sale.

Closing of Spencer Station – On November 5, 2002, PG&E NEG announced its plan to shut down its Spencer Station generating plant located in Denton, Texas. PG&E NEG acquired the 178 MW gas-fired plant in June 2001 and in addition PG&E ET entered into a contract to provide the full service power requirements of the city of Denton for a period of five years beginning July 1, 2001. Despite the closing of the Spencer Station plant, PG&E ET will continue to provide the power requirements under this contract. Completion of the shut down is expected by December 2002. PG&E NEG will incur a pre-tax loss upon shutdown of approximately $4 million which includes costs associated with decommissioning the plant and employee terminations.

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&E Gen 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, including this MD&A, contains 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, 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;

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

• The outcome of PG&E NEG’s negotiations with its lenders under PG&E NEG’s revolving credit facilities, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities, and the Equipment Revolver, as well as with representatives of the holders of the Senior Notes, to reach a global restructuring of this debt which would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG’s merchant assets and reduce trading operations;

• The extent to which PG&E NEG incurs a charge to earnings as a result of the abandonment, sale or transfer of assets, whether such transactions occur in connection with the implementation of a global restructuring as may be agreed to by the lenders or otherwise;

• 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 financial or liquidity constraints, changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others; or by 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 extensions of the maturity date of its revolving credit facility, now due to expire on November 14, 2002, in light of PG&E NEG’s below investment grade credit ratings, liquidity constraints, conditions in the general economy or the energy markets or the capital markets, and the market’s perception of the energy industry;

• The results of negotiations with PG&E NEG’s construction lenders to fund completion of certain generating projects beyond November 14, 2002;

• 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 extent to which counterparties demand collateral in connection with PG&E ET’s trading and nontrading activities which can be affected by the counterparties’ responses to downgrades of PG&E NEG’s and its subsidiaries’ credit ratings, mutual forbearance as many counterparties also have been downgraded, pre- and early-pay arrangements, the continued performance of PG&E NEG companies under the underlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of the exposure, and the counterparties’ other commercial considerations, and the ability of PG&E NEG and its subsidiaries to meet the liquidity calls that may be made;

• The extent to which counterparties seek to terminate tolling agreements based upon the credit downgrades and seek termination damages 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;

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

• 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;

• The effect of the Utility bankruptcy proceedings upon PG&E Corporation and upon PG&E NEG;

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.

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

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 (bcf) 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 increases capacity by an additional 217 million cubic feet (MMcf) per day. Approximately 40 MMcf per day of capacity associated with this expansion was operational in November of 2001. The remaining volumes became operational in November 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 was placed into service in September 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 September 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, as of September 30, 2002 PG&E NEG had five facilities totaling 5,360 MW in construction and controlled, 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 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.

MARKET CONDITIONS AND BUSINESS ENVIRONMENT

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. During 2001 and 2002, new supply additions begun during the high-price period combined with a softening economy and reduced load growth 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. Prior to the economic slowdown, a number of companies, including PG&E NEG, initiated substantial growth plans. These plans included construction and acquisition of new power plants and expansion of energy trading activities. In order to implement these plans, PG&E NEG secured options to purchase long lead-time equipment, acquired certain assets under construction or in operation and completed development and commenced construction of new power plants. These plans required substantial amounts of liquidity and capital resources to support construction, working capital, and counterparty credit requirements. PG&E NEG financed these growth plans and 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 provided working capital, letters of credit and other liquidity needs. These financings and other commitments often relied on the credit support provided by PG&E Corporation. In late 2000 and early 2001, as PG&E Corporation’s credit position deteriorated due to the financial difficulties of the Utility, PG&E NEG and various subsidiaries obtained their own investment grade credit rating and began providing replacement credit support for PG&E NEG’s commitments to implement its growth plans. Due to these industry events, the deterioration of PG&E Corporation’s credit position, collapse of the spark spread, the electric generation overbuild, the decline of energy companies’ credit quality and overall industry poor economic performance, PG&E NEG is currently unable to pay its debts under six major credit facilities as they become due.

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

CREDIT RATINGS

PG&E NEG and its subsidiaries have been downgraded several times since the end of July 2002. The credit ratings as of October 31, 2002 of the various debt instruments of PG&E NEG are as follows:


	Standard		Moody's
	& Poor's		Investors Service

*Rated entities:*




PG&E NEG		B-	B3




PG&E GTN	BB-		Ba1




PG&E ET		B-	Not Rated




PG&E Gen		B-	Not Rated




USGenNE		B-	B2




*Rated debt instruments:*




Senior Unsecured Notes due 2011 (PG&E NEG)		B-	B3




Senior Unsecured Notes due 2005 (PG&E GTN)	BB-		Ba1




Senior Unsecured Debentures due 2025 (PG&E GTN)	BB-		Ba1




Senior Unsecured Notes due 2012 (PG&E GTN)	BB-		Ba1




Medium Term Notes (nonrecourse) PG&E GTN	BB-		Ba1




Term Loan (GenHoldings I, LLC)	CC		B3

The first downgrades to below investment grade occurred on July 31, 2002, three weeks prior to PG&E NEG’s anticipated rollover of its $750 million 364-day revolving credit facility. As a result of the downgrades, the facility was not renewed and instead the outstanding balance ($431 million) initially became due and payable as of August 22, 2002, and remains outstanding under a waiver, described below, which expires November 14, 2002. As described below, PG&E NEG does not expect this waiver to be extended. Absent such extension, PG&E NEG will be in default under the Corporate Revolver. This default would constitute a cross-default under the other major debt facilities and guaranteed commitments described below. Other commitments made in connection with PG&E NEG’s growth plans are also beginning to mature over the next 15 months. This series of events has materially and adversely affected PG&E NEG’s liquidity position and PG&E NEG does not currently have sufficient sources of liquidity to fulfill its commitments as they mature.

LIQUIDITY AND FINANCIAL RESOURCES

PG&E NEG’s and its subsidiaries’ obligations fall into four broad categories: (i) major debt facilities and equity commitments; (ii) PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio excluding tolling agreements; (iii) tolling agreements; and (iv) other guarantees and commitments. In addition to the impacts of PG&E NEG’s downgrades, PG&E NEG’s and its subsidiaries’ ability to service these obligations is impacted by constraints on the ability to move cash from one subsidiary to another or to PG&E NEG itself. PG&E NEG’s subsidiaries must now independently determine, in light of each company’s financial situation, whether any proposed dividend, distribution or intercompany loan is permitted and is in such subsidiary’s interest. Therefore, consolidated statements of cash flow and consolidated balance sheets quantifying PG&E NEG’s cash and cash equivalents do not reflect the cash actually available to PG&E NEG or any particular subsidiary to meet its obligations.

PG&E NEG’s cash bank balances (net of restricted cash bank balances, international accounts and not including in-transit items) at October 31, 2002 is as follows (in millions):


PG&E NEG	$	18




PG&E ET		149




PG&E GEN		38




PG&E GTC		37




Other Subsidiaries		54

Consolidated PG&E NEG	$	296

Major PG&E NEG Debt Facilities and Equity Commitments

PG&E NEG is a party to, or guarantor of, six major facilities:


	Amount Outstanding
Name	(October 31, 2002)	Maturity

PG&E NEG Debt and Guaranteed Debt









Senior Notes	$1 billion	May 15, 2011




Corporate Revolver	$431 million	November 14, 2002




	$273 million*	August 22, 2003




Equipment Revolver	$205 million	Through December 31, 2003









PG&E NEG Equity Commitment Guarantees









GenHoldings Equity Commitment	$355 million	Through Project Completions during 2003




La Paloma Equity Commitment	$375 million	March 2003




Lake Road Equity Commitment	$230 million	March 2003

all amounts as of October 21, 2002, were letters of credit.

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

The agreements for each of these commitments provide for cross-defaults if PG&E NEG fails to pay when due or at maturity, or the lenders accelerate, an amount equal to or in excess of $50 million of any indebtedness or equity commitment. As described below, PG&E NEG expects to default in the repayment of the $431 million due on November 14, 2002, under the Corporate Revolver. This will cause a cross-default under the other five major facilities. PG&E NEG is in discussions with the lenders to restructure these commitments. Notwithstanding the defaults, PG&E NEG believes that the lenders will continue negotiations to restructure PG&E NEG’s obligations. If the lenders exercise their default remedies or no restructuring is achieved, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into Chapter 11 of the Bankruptcy Code. The current status and upcoming milestones for each facility and a description of the restructuring discussions are set forth below.

Senior Notes. Interest on the Senior Notes is payable semi-annually on May 15 and November 15 of each year. The next interest payment of approximately $52 million is due November 15, 2002. PG&E NEG does not expect to make this interest payment. The unsecured Senior Notes are due May 15, 2011.

Corporate Revolver. The Corporate Revolver’s $750 million 364-day tranche was originally due on August 22, 2002. PG&E NEG had expected to renew this tranche for another 364 days. As a result of PG&E NEG’s downgrades to below investment grade at the end of July and beginning of August, this debt was not renewed and instead the $431 million outstanding balance became due and payable on August 22, 2002. On August 22, 2002, the Corporate Revolver was amended to reduce the lenders’ commitments to $500 million and to extend the maturity date to October 21, 2002. On October 21, 2002, the Corporate Revolver was further amended to extend the expiration and renewal date to November 14, 2002 and to reduce the lenders commitments under the 364-day tranche and the two-year tranche to $431 million and $273 million, respectively, which were the amounts outstanding as of October 21, 2002. PG&E NEG does not expect to repay the 364-day tranche on November 14, 2002, nor does PG&E NEG expect a further extension of the maturity date. Absent such extension, PG&E NEG will be in default under the Corporate Revolver and the other five major facilities. The Corporate Revolver is an unsecured revolving credit facility.

Equipment Revolver. The commitments under the Equipment Revolver are scheduled to reduce by $25 million per quarter with the balance due at maturity on December 31, 2003. The next scheduled repayment of $25 million is due on January 1, 2003. PG&E NEG does not currently expect to make this payment nor interest payments when due. The Equipment Revolver is secured by PG&E NEG’s major equipment purchase agreements and is guaranteed by PG&E NEG.

GenHoldings Equity Commitment. Under the GenHoldings credit facility, GenHoldings is committed to make equity contributions to fund construction of the Harquahala, Covert and Athens generating projects. This credit facility is secured by these projects in addition to the Millennium generating facility. PG&E NEG has guaranteed GenHoldings equity commitment. Due to the downgrade to below investment grade by both S&P and Moody’s, PG&E NEG became required to fund construction draws under the GenHoldings credit facility entirely with equity until GenHoldings’ full equity commitment was fulfilled. After GenHoldings fulfilled its equity commitment, the lenders were to fund construction draws in accordance with the credit facility. In August and September 2002, PG&E NEG funded approximately $150 million of the equity commitments, with the outstanding equity commitment at September 30, 2002 remaining at $355 million. In October 2002, PG&E NEG notified the lenders under the GenHoldings credit facility that it would not make further equity contributions on behalf of GenHoldings. On October 24, 2002, GenHoldings and the lenders under the GenHoldings credit facility entered into a Second Waiver and Forbearance Agreement pursuant to which the lenders waived through November 14, 2002, existing defaults under the GenHoldings credit agreement and permitted GenHoldings to borrow up to $50 million and agreed to issue specified letters of credit in a face amount not to exceed $36 million. On October 25, 2002, the lenders funded GenHoldings pending draw request for the Athens, Covert and Harquahala construction projects. The lenders also agreed to forbear until November 14, 2002, from exercising any remedies with respect to existing defaults. PG&E NEG does not expect an extension to this forbearance.

La Paloma Equity Commitment. PG&E NEG guaranteed the repayment of certain debt representing La Paloma’s equity commitment in the aggregate amount of $379 million which is due March 2003. Due to the downgrade to below investment grade by both S&P and Moody’s, PG&E NEG, as guarantor, became required to make equity contributions under the La Paloma credit facility to fund construction costs. In October 2002, PG&E NEG funded $4.5 million of construction costs reducing the outstanding equity commitment at October 31, 2002 to $374.5 million. In October, PG&E NEG notified the lenders under the La Paloma credit facility that it would not make further payments of construction costs for La Paloma. On November 8, 2002, PG&E NEG and the La Paloma lenders entered into an agreement pursuant to which, among other things, the lenders funded on November 8, 2002, the pending draw request to pay construction costs. PG&E NEG does not currently expect to have sufficient funds to make the $374.5 million payment in March 2003.

Lake Road Equity Commitment. PG&E NEG guaranteed the repayment of certain debt representing Lake Road’s equity commitment in the aggregate amount of $230 million which is due March 2003. Lake Road entered commercial operation in May 2002. PG&E NEG does not currently expect to have sufficient funds to make the payment in March 2003.

Debt Restructuring Efforts

PG&E NEG’s efforts to reduce debt or raise cash through various efforts, including asset sales, have failed to produce adequate sources of liquidity for PG&E NEG to meet its obligations. PG&E NEG, therefore, has been in active negotiations regarding a global restructuring of its debt with the lenders under the Corporate Revolver, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities and the Equipment Revolver as well as representatives of the holders of the Senior Notes. This global restructuring would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG’s merchant assets and reduce energy trading operations. If agreed to by PG&E NEG’s lenders and implemented by PG&E NEG, these various asset transfers, sales and abandonments would cause substantial charges to earnings in either the fourth quarter of 2002 or in 2003.

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

PG&E Corporation, has disclosed in a Current Report on Form 8-K that on October 18, 2002, PG&E Corporation entered into a Second Amended and Restated Credit Agreement with the lenders party thereto, Lehman Commercial Paper Inc., as Administrative Agent, and others (the “Loan Agreement”). Under the Loan Agreement, PG&E Corporation agreed, among other things, not to permit PG&E NEG or any of its subsidiaries to (i) sell or abandon any of their respective assets except in compliance with certain conditions, or (ii) restructure any of their respective indebtedness except in compliance with certain conditions. These prohibitions do not apply to a “Qualified Asset Sale,” a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring,” all as defined in the Loan Agreement. In general, these definitions permit transactions in which, among other things, PG&E Corporation (i) is released from existing liabilities related to the assets that are the subject of the transaction, (ii) incurs no new liabilities as a result of the transaction, and (iii) receives payment at closing for any taxes that would be payable as a result of the transaction if PG&E NEG and its subsidiaries were a separate group for tax purposes.

PG&E NEG and its subsidiaries are included in the federal consolidated tax return of PG&E Corporation. The Loan Agreement also restricts PG&E Corporation’s investment in PG&E NEG to, with limited exceptions, an amount that is no more than 75 percent of the net cash tax savings received by PG&E Corporation after October 1, 2002, as a result of a “Qualified Asset Sale,” a “Qualified Bankruptcy Sale,” a “Qualified Abandonment,” or a “Qualified Restructuring,” (as defined in the Loan Agreement) by PG&E NEG.

PG&E NEG is not a party to the Loan Agreement.

PG&E NEG received a letter dated November 12, 2002 from PG&E Corporation regarding PG&E Corporation’s consolidated tax returns. The letter refers to “recent discussions regarding whether the manner in which PG&E Corporation and PG&E NEG have handled PG&E NEG’s tax losses in the past may constitute a course of conduct from which an agreement may be implied that is somehow legally binding on PG&E Corporation,” and states that, “To the extent any such implied contract ever existed and was not previously terminated, we hereby give you notice of the termination of such agreement, effective immediately.” PG&E NEG is currently investigating all aspects of its tax-sharing arrangements with PG&E Corporation, including whether the purported termination referenced in the letter is effective without the consent of PG&E NEG.

Major Subsidiary Debt

PG&E NEG’s subsidiaries are parties to three major facilities:

Amount Outstanding

Name

Aggregate Commitment

(as of October 31, 2002)

Maturity

GTN Notes

$506 million

2003-2025

GTN Revolver

$125 million

none drawn

May 2005

USGenNE Revolver

$100 million

$89 million

August 2003

PG&E NEG’s subsidiaries are also parties to three other revolving credit facilities with aggregate commitments totaling $70 million.

PG&E GTN Notes. PG&E GTN pays interest on the GTN Notes semiannually in June and December with the next interest payment of approximately $15 million due in December 2002. PG&E GTN is current on its obligations on the GTN Notes.

PG&E GTN Revolver. PG&E GTN pays interest on the GTN revolver quarterly if any balances are outstanding. As of October 31, 2002, no amounts are drawn. PG&E GTN is current on its obligations under the GTN Revolver.

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

USGenNE Revolver. Of the $89 million outstanding under this facility as of October 31, 2002, $75 million are loans and $14 million are letters of credit. USGenNE pays interest on the USGenNE Revolver quarterly with the next interest payment of $0.5 million due December 20, 2002. USGenNE is current on its obligations under the USGenNE Revolver.

Activities Related to Merchant Portfolio Operations

PG&E NEG and certain subsidiaries have provided guarantees to approximately 250 counterparties in support of PG&E ET’s energy trading and non-trading activities related to PG&E NEG’s merchant energy portfolio in the face amount of $2.8 billion (including $69 million in guarantees pursuant to pipeline tariff provisions and $89 million in guarantees to power pools which have an aggregate exposure of less than $1 million). 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 October 27, 2002, PG&E NEG and its subsidiaries’ aggregate net exposure under these guarantees was approximately $180 million, as follows: PG&E NEG $87 million; PG&E GTN $65 million; PG&E ET $27 million; and USGenNE $1 million. The amount of such exposure varies daily depending on changes in market prices and net changes in position. In light of the downgrades, some counterparties have sought and others may seek replacement security to collateralize the exposure guaranteed by PG&E NEG and its various subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will provide no new guarantees on behalf of PG&E ET.

At October 27, 2002, PG&E ET’s estimated exposure not covered by a guarantee (excluding exposure under tolling agreements) is approximately $106 million.

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

Tolling Agreements

The face amount of PG&E NEG’s and its subsidiaries’ guarantees relating to PG&E ET’s tolling agreements is approximately $600 million. The five tolling agreements are with: (1) Liberty Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE) guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P. (Calpine) for which no guarantee is in place; (4) Southaven Power, LLC (Southaven) guaranteed by PG&E NEG for up to $176 million; and (5) Caledonia Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

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

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

Calpine — The tolling agreement states that on or before October 15, 2002, Calpine was to have issued a full notice to proceed under its construction contract to its engineering, procurement and construction contractor for the facility. On October 16, 2002, PG&E ET asked Calpine to confirm that it had issued this full notice to proceed and Calpine was not able to do so to the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter dated October 30, 2002, that it was terminating the tolling agreement effective November 29, 2002. PG&E NEG was required to provide in December 2002, a guarantee of PG&E ET’s payment obligations under a 10-year tolling agreement with Calpine involving the Otay Mesa facility. The guarantee amount was not to exceed $20 million. As a result of the termination of the tolling agreement, PG&E NEG believes it is no longer obligated to provide a guarantee.

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

Southaven — PG&E ET signed a tolling agreement with Southaven dated as of June 1, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment–grade, as defined in the agreement. The amount of the guarantee now does not exceed $176 million. The original maximum amount of the guarantee was $250 million, but this amount was reduced by approximately $74 million, the amount of a subordinated loan that PG&E ET made to Southaven on August 31, 2002, pursuant to a subordinated loan agreement between PG&E ET and Southaven. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment–grade as defined in the agreement and because PG&E ET had failed to provide within thirty days from the downgrade substitute credit support that meets the requirement of the agreement. Under the agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Caledonia — PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, pursuant to which PG&E ET is to provide credit support that meets certain requirements set forth in the agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment grade, as defined in the agreement. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment grade as defined in the agreement and because PG&E ET had failed to provide within thirty days from the affiliate’s downgrade substitute credit support that meets the requirement of the agreement. Under the agreement, Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia’s performance under the agreement. If this default is not cured, PG&E ET has the right to terminate the agreement and seek recovery of a termination payment.

Other Guarantees

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. Attala Energy Company is currently experiencing a negative cash flow performing under this agreement and requires cash infusions in order to perform its obligations. PG&E NEG may stop making cash infusions to Attala Energy Company which could cause a default under the Attala sale–leaseback financing.

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 has issued guarantees with an aggregate face value of up to approximately $175 million in connection with these equipment commitments. PG&E NEG’s commitment to purchase combustion turbines and related equipment exceeds its current planned development activities. PG&E NEG and its equipment vendors have agreed to suspend any PG&E NEG payment obligations (except for $14 million as of October 31, 2002) for at least the next nine months. The $14 million is due January and July, 2003. Beginning in September 2003, 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 NEG estimates these termination costs, and its exposure under these guarantees, to be approximately $53 million as of October 31, 2002 (including the $14 million as of October 31, 2002).

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

Other Commitments

PG&E NEG’s subsidiary has executed construction contracts for its Smithland and Cannelton projects for up to 163 MW at two hydroelectric facilities on the Ohio River in Kentucky. As of September 30, 2002, PG&E NEG had recorded assets of $1.8 million for these projects, representing equipment payments and development costs. PG&E NEG’s subsidiary had commenced construction of the first 16 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. The reevaluation is complete and the Army Corps of Engineers concurs that the new seismic criteria will not require any design changes. PG&E NEG’s subsidiary has not resumed construction. The construction contractor is the beneficiary of a letter of credit securing PG&E NEG’s subsidiary’s termination payment obligations. If PG&E NEG’s subsidiary terminates construction of this project, the construction contractor will be entitled to draw on the letter of credit for approximately $7 million.

Material Notices

Other Matters

On November 4, 2002, affiliates of PG&E NEG entered into an agreement to sell 49.9 percent of its ownership interest in Hermiston Generating Company, L.P. (HGC) to Sumitomo Corporation and Sumitomo Corporation of America. The buyer was granted an option to purchase, during the three month period beginning thirteen months immediately following the closing date, an additional 0.1 percent interest (at the fair market value at the date of exercise). HGC owns an undivided 50 percent interest in a 474 MW gas-fired generating plant in Hermiston, Oregon. The other 50 percent is owned by PacifiCorp who also purchases the output of the plant under a long-term contract. The sale is expected to be completed by December 31, 2002, following the receipt of necessary regulatory approvals. At September 30, 2002, book value of PG&E NEG’s investment in Hermiston was approximately $44 million. PG&E NEG anticipates a pre-tax gain of approximately $23 million upon completion of the sale.

On November 5, 2002, PG&E NEG announced its plan to shut down its Spencer Station generating plant located in Denton, Texas. PG&E NEG acquired the 178 MW gas-fired plant in June 2001 and in addition PG&E ET entered into a contract to provide the full service power requirements of the city of Denton for a period of five years beginning July 1, 2001. Despite the closing of the Spencer Station plant, PG&E ET will continue to provide the power requirements under this contract. Completion of the shut down is expected by December 2002. PG&E NEG will incur a pre-tax loss upon shut down of approximately $4 million which includes costs associated with decommissioning the plant and employee terminations.

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

PG&E NEG holds an indirect 50 percent interest in Logan Generating Company, L.P. (Logan). Logan leases and operates a 225 MW coal-fired cogeneration facility in New Jersey that sells its output to Conectiv. On October 29, 2002, the long-term coal supplier, Anker Energy Corporation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Under the terms of Logan’s non-recourse project financing, this filing constitutes a default, which Logan has sixty days to cure. The agent for Logan’s lenders notified Logan that an event of default shall have occurred if not cured during the sixty day period. Logan is seeking a waiver from its lenders and hopes to either have the coal supply contract assumed by Anker in bankruptcy or, if it is rejected by Anker, replaced by a similar agreement with another supplier. Until such time as the default is cured or waived, Logan will be unable to distribute cash to its partners. In 2001, Logan distributed $11.6 million to PG&E NEG. During the nine months ended September 30, 2002, Logan distributed $6.0 million to PG&E NEG.

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 36 additional instances. These instances had no material effect on PG&E NEG’s reported revenues or financial results. Revenues associated with these instances represent an immaterial amount 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 coverage’s will be at lower levels than PG&E NEG has historically procured, certain coverage’s (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.

PG&E NEG implemented a program to reduce administrative, general and other operating costs by a minimum of $50 million measured from 2001 actual costs.

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 nine months ended September 30, 2002, PG&E NEG used net cash from operations of $23 million compared to net cash generated from operations of $316 million for the same period in 2001, or a decrease of $339 million. Net income declined by $424 million between periods, but net income with adjustments to reconcile net income to net cash provided in operating activities, results in improved operating cash flow by $109 million period to period. The increase from period to period was primarily due to realization of cash from 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, including other net items, of $448 million period to period. The cash flows used for operating assets and liabilities, including other net items, increased primarily due to additional prepayments and deposits needed as a result of the credit rating downgrades. Included in Investing Activities for the nine months ended September 30, 2002 and 2001, is a cash flow of $61 million and $60 million respectively related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities.

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 nine months ended September 30, 2002, PG&E NEG used net cash of $957 million in investing activities compared to $1,146 million for the same period in 2001, or a decrease of $189 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 $1,307 million for the nine months ended September 30, 2002, versus $957 million for the nine months ended September 30, 2001. Total capital expenditures, including construction expenditures, by segment are shown in the below table (in millions):


		Three months ended				Nine months ended
		September 30,				September 30,

		2002		2001		2002		2001

Capital Expenditures:




	Integrated Energy and Marketing Activities	$	346	$	459	$	1,165	$	1,008




	Interstate Pipeline Operations		45		28		163		51

Total Capital Expenditures		$	391	$	487	$	1,328	$	1,059

Advanced development and turbine prepayments were $9 million and $216 million for the nine-month periods September 30, 2002 and 2001, respectively. Also during the nine months ended September 30, 2001, several projects were moved from advanced development activities to construction work in progress for approximately $160 million, and the purchase of the Mountain View wind projects for $92 million. No comparable activities occurred during the nine months ended September 30, 2002. As a result of investment downgrades PG&E ET replaced a $74 million letter of credit issued to Southaven Power, LLC with cash pursuant to a subordinated loan agreement. This cash expenditure is reflected in PG&E NEG’s cash used in investing activities. Included in Investing Activities for the nine months ended September 30, 2002 and 2001, is a cash flow of $61 million and $60 million respectively related to the long-term receivable from New England Power Company associated with the assumption of power purchase agreements. These cash flows offset cash payments made to New England Power Company which are reflected in operating activities. Other net expenditures were $22 million and $1 million for the nine months ended September 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 assuming the lenders continue to fund construction:

Percentage

Projected

Projects

Location

Completion

In-Service Dates

MW's

Athens

New York

70%

3rd Quarter, 2003

1080

Covert

Michigan

61%

3rd Quarter, 2003

1170

Harquahala

Arizona

69%

3rd Quarter, 2003

1092

La Paloma

California

99%

1st Quarter, 2003

1121

Mantua Creek

New Jersey

22%

Undetermined

897

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

On October 24, 2002, GenHoldings and the lenders under the GenHoldings credit facility entered into a Second Waiver and Forbearance Agreement pursuant to which the lenders waived through November 14, 2002, existing defaults under the GenHoldings credit agreement to allow GenHoldings to (i) borrow up to $50 million and (ii) issue specified letters of credit in a face amount not to exceed $36 million. On October 25, 2002, the lenders funded GenHoldings pending draw request for the Athens, Covert and Harquahala construction projects. The lenders also agreed to forbear until November 14, 2002, from exercising any remedies with respect to existing defaults. PG&E NEG does not expect this forbearance to be extended.

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 requested and the intervenor group has appealed. The appeals court affirmed the lower court’s denial of the preliminary relief requested.

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

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 September 30, 2002, for its portfolio of development projects is $49 million. PG&E NEG anticipates continuing to develop these projects to completion or for future disposal. 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 $53 million as of October 31, 2002 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 terminated its commitments or options with respect to only three turbines and related equipment. The remaining asset value (recorded in Other Non Current Assets) that PG&E NEG has retained as of September 30, 2002, for its investment in turbines and related equipment is approximately $34 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 $14 million as of October 31, 2002) for at least the next nine months. The $14 million is due in January and July 2003. Beginning in September 2003, 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 has substantially completed its 2002 Expansion Project, expanding its system by approximately 217 MMcf per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001 and the remaining capacity was placed in service in November 2002. The total cost of the expansion is approximately $127 million. One shipper contractually committed to 175,000 Dth per day of capacity on this project failed to provide PG&E GTN with adequate assurances of the shipper’s ability to meet its obligations under its transportation contract. PG&E GTN and that shipper subsequently terminated the transportation contract and PG&E GTN has received $16.8 million from that shipper in settlement of the contract.

In response to changing market conditions, PG&E GTN reached agreement with all shippers contractually committed to a second expansion (2003 Expansion Project) to terminate their firm transportation precedent agreements. Accordingly, on October 10, 2002, PG&E GTN filed with the FERC a request to vacate its 2003 Expansion proceeding and deferred the project. To date, PG&E GTN has spent $5.3 million on the 2003 Expansion Project. PG&E GTN is continuing necessary development activities and expects to refile an application with FERC when market conditions improve.

Each of the former 2003 Expansion shippers has committed to take capacity on PG&E GTN’s system made available as a result of the 2002 shipper termination, capacity formerly held by Enron, or other existing capacity on PG&E GTN’s system. PG&E GTN anticipates that it will enter into additional contracts for capacity made available from these sources through open market sales. As of November 8, 2002, PG&E GTN had approximately 155,000 Dth per day of capacity available for subscription on a long-term basis.

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 initiated preliminary assessments of lateral pipelines that would originate on the PG&E GTN mainline system and would extend to metropolitan areas in the Pacific Northwest.

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

North Baja Pipeline—PG&E NEG is constructing a new 500 million cubic feet per day gas pipeline, North Baja, to deliver natural gas to Northern Mexico and Southern California. North Baja will consist of approximately 80 miles of pipe and 25,000 HP of compression. The pipeline segment of North Baja was placed into service in September 2002, and the compression facilities are expected to be completed by the end of 2002. At September 30, 2002, PG&E NEG had spent approximately $137 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 $156 million.

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 was held on September 13, 2002. A decision is expected soon.

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 nine months ended September 30, 2002, and 2001, PG&E NEG provided net cash flows from financing activities of $626 million and $818 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 conducts risk management activities in a manner, which supports business objectives, minimizes costs, and discourages unauthorized physical and financial risk through a strong internal control environment. PG&E NEG intends to manage exposures to market, credit, volumetric, regulatory, operational, and reliability risks to manage the volatility of earnings and cash flows. Such risks are managed using cost-effective risk management programs that may include the use of energy and financial derivative instruments and other instruments and agreements. These derivatives include forward contracts, futures, swaps, options, and other contracts.

• A forward contract is a commitment to purchase or sell energy commodities at a specified future date at a specified price;

• a futures contract is a standardized commitment, traded on an organized exchange, to purchase or sell an energy commodity or financial instrument at a specified future date at a specified price;

• a swap agreement requires payments for a quantity of an energy commodity based upon the difference between agreed upon prices; and

• an option contract provides the right, but not the obligations, to buy or sell the underlying commodity at a predetermined price in the future.

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

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


	Three Months Ended			Nine Months Ended
	September 30, 2002			September 30, 2002

Fair values of trading contracts at beginning of period	$	(1	)	$	33




Net gain on contracts settled during the period		84			165




Fair value of new contracts when entered into		2			2




Changes in fair values attributable to changes in valuation techniques and assumptions		(12	)		(12	)




Other changes in fair values		(63	)		(178	)

Fair values of trading contracts outstanding at end of period	$	10		$	10




Fair values of non-trading contracts at end of period		(422	)		(422	)

Net price risk management liabilities at end of period	$	(412	)	$	(412	)

The changes in fair values attributable to changes in valuation techniques and assumptions, as reported in the table above, are composed of a $14 million loss related to PG&E NEG’s implementation of a new methodology for estimating forward prices in illiquid periods and a $2 million gain related to changes in assumptions used to value transportation contracts. The change in forward prices is described more fully in Note 1 to the Consolidated Financial Statements.

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

PG&E NEG estimated the fair value of its trading contracts as of September 30, 2002, using the midpoint 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 uses its forward price curve methodology described in Note 1 to the Consolidated Financial Statements. 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 following table shows the fair value of PG&E NEG’s trading contracts by maturity at September 30, 2002 (in millions):


	Fair Value of Trading Contracts⁽²⁾ at September 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	$	(10	)	$	8		$	4		$	—		$	2




Provided by other external sources		14			(22	)		(13	)		(1	)		(22	)




Based on models and other valuation methods⁽¹⁾		3			(14	)		(12	)		53			30

Total Mark to Market	$	7		$	(28	)	$	(21	)	$	52		$	10

⁽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 will adversely affect earnings and cash flow. 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 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 price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the probability of future potential losses. Price risk is quantified using a variance/co-variance value-at-risk model that provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of important assumptions, including the selection of a confidence level for losses, volatility of prices, market liquidity, and a holding period.

PG&E NEG uses historical data for calculating the price volatility of its contractual positions and how likely the prices of those positions will move together. The model includes all derivatives and commodity instruments in the trading and non-trading portfolios. PG&E NEG expresses value-at-risk as a dollar amount of the potential loss in the fair value of its portfolios based on a 95 percent confidence level using a one-day 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 September 30, 2002 (in millions):


Trading Activities		$	3




Non – Trading Activities:




	Non-Trading Contracts that Receive Mark To Market Accounting Treatment⁽¹⁾	$	2




	Non-Trading Contracts Accounted for as Hedges⁽²⁾	$	19

⁽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.

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 working capital facilities, the risk of increasing interest rates on new money notes and exchange notes used for debt re-financings, and the risk of increasing rates on variable rate tax exempt pollution control bonds.

PG&E NEG may use the following interest rate instruments to manage its interest rate exposure: interest rate swaps, interest rate caps, floors, or collars, swaptions, or interest rate forward and futures contracts. Interest rate risk sensitivity analysis is used to measure interest rate risk by computing estimated changes in cash flows as a result of assumed changes in market interest rates. As of September 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 before 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 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.

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

PG&E NEG uses sensitivity analysis to measure its foreign currency exchange rate exposure to the Canadian dollar. Based on a sensitivity analysis at September 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 accounting loss that PG&E NEG would incur if counterparties fail to perform their contractual obligations (net 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, such as investor owned and municipal utilities, energy trading companies, financial institutions, and oil and gas production companies located in the United States and Canada. This concentration of counterparties may impact the overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory, or other conditions. PG&E NEG manages credit risk pursuant to its Risk Management Policies, which provide processes by which counterparties are assigned credit limits in advance of entering into significant exposure. These procedures include an evaluation of a potential counterparty’s financial condition, net worth, credit rating, and other credit criteria as deemed appropriate, and are performed at least annually. Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, PG&E NEG takes immediate action to reduce exposure and/or obtain additional collateral. Further, PG&E NEG relies heavily on master agreements that contain credit support provisions that require the counterparty to post security in the form of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceed contractually specified limits.

As of September 30, 2002, no single customer represents greater than 10 percent of PG&E NEG’s net credit exposure.


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

$1,068		$131	$	937

⁽¹⁾		Gross credit exposure equals fair value (adjusted for applicable credit valuation adjustments), notes receivable, net (payables) receivables where netting is allowed. Gross and net credit exposure amounts reported above do not include adjustments for time value or liquidity.




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

At September 30, 2002, approximately $200 million or 21 percent of PG&E NEG’s net credit exposure is to entities that have credit ratings below investment grade. Investment grade is determined using publicly available information (i.e., rated at least Baa3 by Moody’s and BBB- by S&P). Approximately $86 million or 9 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.

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

RESULTS OF OPERATIONS

The table shows for the three months and nine months ended September 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		(2)			TOTAL

Three months ended September 30, 2002




Total operating revenues ⁽¹⁾	$	1,030		$	62	$	(5	)	$	1,087




Total operating expenses		1,114			26		(3	)		1,137

Total operating income		(84	)		36		(2	)		(50	)

Interest income										14




Interest expense										54




Other income (expense), net										4




Income (loss) before income tax										(86	)




Income taxes benefit										(68	)




Income (loss) before cumulative effect of a change in accounting principle										(18	)




Net income (loss)										(18	)




Net cash used by operating activities										(41	)




Net cash used in investing activities										(427	)




Net cash provided by financing activities										73




EBITDA ⁽³⁾	$	(49	)	$	53	$	1		$	5




Three months ended September 30, 2001




Total operating revenues ⁽¹⁾	$	733		$	57	$	(8	)	$	782




Total operating expenses		626			30		(10	)		646

Total operating income		107			27		2			136

Interest income										23




Interest expense										48




Other income (expense), net										(4	)




Income before income tax										107




Income taxes provision										30




Net Income										77




Net cash provided by operating activities										282




Net cash used in investing activities										(473	)




Net cash provided by financing activities										116




EBITDA ⁽³⁾	$	132		$	42	$	3		$	177

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


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

For the Nine Months ended September 30, 2002




Total operating revenues ⁽¹⁾	$	2,277		$	175	$	(14	)	$	2,438




Total operating expenses		2,633			77		(3	)		2,707

Total operating income		(356	)		98		(11	)		(269	)

Interest income										46




Interest expense										143




Other income (expense), net										1




Income (loss) before income tax										(365	)




Income taxes benefit										(204	)




Income (loss) before cumulative effect of a change in accounting principle										(161	)




Net income (loss)										(222	)




Net cash used by operating activities										(23	)




Net cash used in investing activities										(957	)




Net cash provided by financing activities										626




EBITDA ⁽³⁾	$	(263	)	$	143	$	(8	)	$	(128	)




For the Nine Months ended September 30, 2001




Total operating revenues ⁽¹⁾	$	2,042		$	186	$	(4	)	$	2,224




Total operating expenses		1,801			80		(3	)		1,878

Total operating income		241			106		(1	)		346

Interest income										72




Interest expense										106




Other income (expense), net										2




Income before income tax										314




Income taxes provision										112




Net Income										202




Net cash provided by operating activities										316




Net cash used in investing activities										(1,146	)




Net cash provided by financing activities										818




EBITDA ⁽³⁾	$	324		$	141	$	3		$	468

Footnotes

⁽¹⁾		Operating revenues and operating expenses for the three months and nine months ended September 30, 2002, reflect the adoption of a new accounting policy implementing a change from gross to net method of reporting revenues and expenses on trading activities. The amounts for trading activities for the comparative periods in 2001 have been reclassified to conform with the new net presentation.
⁽²⁾		All inter-segment transactions are eliminated.




⁽³⁾		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 and Nine Months Ended September 30, 2002 as Compared to Three Months and Nine Months Ended September 30, 2001.

Overall Results:

PG&E NEG’s net loss was $18 million for the three months ended September 30, 2002, a decrease of $95 million from the three months ended September 30, 2001. PG&E NEG’s pre-tax operating income decreased $186 million for the three months ended September 30, 2002 compared to the same period in 2001. Gross margins improved slightly during the third quarter 2002 compared to 2001, but PG&E NEG took various one-time charges to pre-tax operating income that more than offset gross margin improvements. As of September 30, 2002, PG&E NEG had recorded, within the PG&E NEG Integrated Energy and Marketing segment, approximately $95 million of net goodwill on its balance sheet. Based upon significant adverse changes within the national energy markets PG&E NEG tested, within the third quarter 2002, for possible impairment of goodwill balances and determined that the book value of PG&E NEG’s Integrated Energy and Marketing segment was greater than the fair value. As such, PG&E NEG determined that the $95 million net goodwill balance was not supportable and should be charged to earnings in the current period. Also, during the third quarter, based on the changes in national energy markets and specifically the markets that PG&E NEG Dispersed Generation’s assets operate, PG&E NEG assessed the probability of utilizing various Dispersed Generation assets (including turbines, generators, transformers, metering equipment, etc.) for expansion. PG&E NEG measured the estimated capital investment necessary for expansion against the future estimated cash flows to be generated. It was determined that such investments would be uneconomical and that PG&E NEG cannot characterize these expansion projects as probable. The book value of this equipment was approximately $46 million at September 30, 2002. Based on recent market quotes and expected net salvage values, PG&E NEG has recorded an impairment charge of approximately $30 million in the third quarter of 2002. Both the impairment of goodwill and impairment of Dispersed Generation assets are included in the impairments and write-offs line item on PG&E NEG’s consolidated statements of operations in the three months and nine months ended September 30, 2002. In addition, PG&E NEG initiated in the third quarter of 2002 a program to reduce future administrative, general and operating costs. This cost reduction program created one-time charges to operating income of approximately $19 million of employee termination costs as well as costs associated with various office closures. Interest income was less for the three months ended September 30, 2002, compared to the prior year primarily due to decreased cash balances on hand. PG&E NEG’s tax benefits for the three months ended September 30, 2002 were based on reduced income levels as compared to the same period last year and certain energy tax credits. In addition, in the quarter ended September 30, 2002, PG&E Corporation re-evaluated its position with respect to expected realization of certain synfuel tax credits and as a result PG&E NEG recorded additional tax benefits totaling $43 million.

PG&E NEG’s net loss (after cumulative effect of a change in accounting principle) was $222 million for the nine months ended September 30, 2002, a decrease of $424 million from the nine months ended September 30, 2001. The nine months ended September 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 $615 million mainly due to impairments and write-offs of long-term turbine prepayments and related capitalized development costs of $265 million, goodwill write-offs of $95 million and impairments of PG&E NEG’s Dispersed Generation assets of $30 million. Also contributing to the decline in pre-tax operating income were 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. Interest income was less for the nine months ended September 30, 2002, compared to the prior year primarily due to decreased cash balances on hand. PG&E NEG’s tax benefits for the nine months ended September 30, 2002 were based on reduced income levels as compared to the same period last year and certain energy tax credits and the changes noted above.

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

Operating Revenues:

PG&E NEG’s operating revenues were $1.1 billion in the three months ended September 30, 2002, an increase of $305 million from the three months ended September 30, 2001. This increase occurred principally in the Integrated Energy and Marketing Activities segment with a slight increase in revenue from Interstate Pipeline Operations. The principal drivers in this increase were in PG&E NEG’s asset generation business providing wholesale energy revenues as a result of settled volume increases compared to prior year and new generation plants coming on line; as well as increased tolling revenues in PG&E NEG’s energy trading operations. Settled volume increases were somewhat offset by declines in commodity prices and continued compressed spark spreads through the third quarter in 2002 as compared to the same period last year. Interstate Pipeline Operations operating revenues increased $5 million due to additional revenue collected as a result of negotiated contract termination settlements.

PG&E NEG’s operating revenues were $2.4 billion in the nine months ended September 30, 2002, an increase of $214 million from the nine months ended September 30, 2001. These occurred primarily in the Integrated Energy and Marketing Activities segment. The principle drivers in this increase were in PG&E NEG’s asset generation business providing wholesale energy revenues as a result of settled volume increases compared to prior year and new generation plants coming on line; as well as increased tolling revenues in PG&E NEG’s energy trading operations. Settled volume increases were somewhat offset by declines in commodity prices and continued compressed spark spreads through the third quarter in 2002 as compared to the same period last year. Interstate Pipeline Operations operating revenues declined $11 million due to weak pricing fundamentals on gas transportation to the California and Pacific Northwest gas markets compared to the same period last year partially offset by contract termination settlements in the third quarter 2002.

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

Operating Expenses:

PG&E NEG’s operating expenses were $1.1 billion in the three-month period ended September 30, 2002, an increase of $491 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 $301 million in line with the increases in operating revenues, compressed spark spreads and new generation plants coming on line within the wholesale energy business. Administrative and general costs increased in the third quarter of 2002 as compared to the same period last year principally due to PG&E NEG’s one-time charges associated with employee termination costs and office closures. Impairments and write-offs were $125 million in the third quarter of 2002, with no comparable charges in 2001, for goodwill write-offs of $95 million and impairment of PG&E NEG’s Dispersed Generation assets of $30 million. Operations, maintenance and management costs increased $25 million and depreciation and amortization costs increased $6 million in the third quarter of 2002 as compared to the same period last year principally due to the operations of new plants coming on line.

PG&E NEG’s operating expenses were $2.7 billion in the nine-month period ended September 30, 2002, an increase of $829 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 $372 million in line with the increases in operating revenues, compressed spark spreads and new generation plants coming on line within the wholesale energy business. Included in operating expenses is approximately $390 million of impairment charge relative to previously capitalized turbine prepayments and related capitalized development cost of $265 million in the second quarter 2002, goodwill write-offs of $95 million in the third quarter 2002, and impairment of PG&E NEG’s Dispersed Generation assets of $30 million in the third quarter 2002. Operations, maintenance and management costs increased $60 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 $20 million in the period also mainly due to new plants coming on line. Administrative and general costs increased in the third quarter of 2002 as compared to the same period last year due to one-time charges associated with the PG&E NEG cost reduction program which were offset on a year to date basis by lower costs in the first half of 2002 associated with lower employee related expense.

CRITICAL ACCOUNTING POLICIES

Effective 2001, PG&E NEG adopted Statement of Financial Accounting Standards (SFAS) No. 133, as amended by SFAS No. 138, “Accounting for Derivative Instruments and Hedging Activities” (collectively SFAS No. 133), which required all financial instruments to be recognized in the financial statements at market value. See further discussion in Price Risk Management Activities above, and Notes 1 and 4 to the Consolidated Financial Statements. PG&E NEG accounts for its energy trading activities in accordance with Emerging Issues Task Force (EITF) 98-10 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities.” and SFAS No. 133 which require certain energy trading contracts to be accounted for at fair values using mark-to-market accounting. For the third quarter ended September 30, 2002, PG&E NEG adopted the net method of recognizing energy trading contracts in the income statement. Under the net method, revenues and expenses are netted and only the trading margin (or loss) is reflected in revenues.

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.

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.

See Note 1 of the Notes to the Consolidated Financial Statements for further discussion of accounting policies and new accounting developments.

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

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

In October 2002, the EITF Taskforce rescinded EITF 98-10. Energy trading contracts that are derivatives in accordance with SFAS No. 133 will continue to qualify for fair value accounting under SFAS No. 133. Contracts that had been marked to market under EITF 98-10 that do not meet the definition of a derivative will be recorded on a cost basis with a one-time adjustment to be recorded as a cumulative effect of a change in accounting principle as of January 1, 2003.

The EITF Taskforce also delayed the implementation (to January 1, 2003) of EITF 02-03, “Recognition and Reporting of Gains and Losses on Energy Trading Contracts under EITF 98-10, ‘Accounting for Contracts Involved in Energy Trading and Risk Management Activities,’ and EITF 00-17, ‘Measuring the Fair Value of Energy Related Contracts in Applying EITF 98-10’” (EITF 02-03). The official guidance related to EITF 02-03 will be outlined in the final minutes of the recent EITF Taskforce meeting scheduled for release in November 2002.

In June 2002, the Financial Accounting Standards Board (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 EITF 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 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.

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

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

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 million (including interest) related to PG&E NEG. PG&E Corporation has filed protests contesting certain adjustments made by the IRS in that audit and is currently discussing those adjustments with the IRS’ Appeals Office. The IRS is also auditing PG&E Corporation’s 1999 and 2000 consolidated U.S. federal income tax returns, but has not issued its final report. However, the IRS has proposed adjustments totaling $66 million (including interest) with respect to PG&E NEG. In addition, PG&E Corporation initiated discussions with the IRS regarding advance determination of a 2001 tax return position with respect to PG&E NEG’s energy tax credits. Those discussions were not completed by the deadline for filing the 2001 tax return and the discussions were terminated. All of PG&E Corporation’s federal income tax returns before 1997 have been closed, including those portions attributable to PG&E NEG. In addition, California and certain other state tax authorities are currently auditing various state tax returns. In the quarter ended September 30, 2002, PG&E Corporation re-evaluated its position with respect to expected realization of certain synfuel tax credits and as a result PG&E NEG recorded additional tax benefits totaling $43 million.

PG&E NEG is not a party to the Loan Agreement.

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 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.)

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Based on an evaluation of PG&E NEG’s disclosure controls and procedures conducted on October 18, 2002, PG&E NEG’s principal executive and principal financial officers have concluded that such controls and procedures effectively ensure that information required to be disclosed by PG&E NEG in reports the company files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported, within the time periods specified in the Securities and Exchange Commission (SEC) rules and forms.

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

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 NEG’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 September, the Court heard oral argument on plaintiff’s motion to remand the proceeding as well as to dismiss certain claims pending against various cross-defendants. The judge has not yet ruled on these motions.

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 enjoining 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 October 11, 2002, the Judicial Panel on Multidistrict Litigation entered a final 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. The defendants have filed a joint motion to dismiss and oral argument is scheduled on the motion for December 19, 2002.

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, California Power Exchange (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 FERC denied on September 23, 2002.

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 which was submitted on October 4, 2002. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse 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 was held on September 13, 2002, and a decision is expected shortly.

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, in addition to challenging issuance of the permit. The court declined to grant the preliminary injunctive relief and the intervenor group appealed this decision to the U.S. Court of Appeals for the Second Circuit. On October 9, 2002, the Court of Appeals affirmed the decision of the district court. 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 Second Amendment to Credit Agreement, dated as of October 18, 2002, to the Amended and Restated Credit Agreement, dated as of August 22, 2001, among PG&E National Energy Group, Inc., JPMorgan Chase Bank (formerly known as The Chase Manhattan Bank), as Issuing Bank, the several lenders from time to time parties thereto, the Documentation Agents thereunder, the Syndication Agents thereunder, and JPMorgan Chase Bank, as Administrative Agent (Incorporated by reference to Current Report on Form 8-K filed October 28, 2002 by PG&E NEG, Exhibit 10.1).

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

99.2 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 three 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

3. Current Report on Form 8-K filed August 6, 2002

4. Current Report on Form 8-K filed August 26, 2002

5. Current Report on Form 8-K filed October 10, 2002

6. Current Report on Form 8-K filed October 21, 2002

7. Current Report on Form 8-K filed October 28, 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:	November 12, 2002	By:	/s/ Thomas G. Boren









			Thomas G. Boren




			President and Chief Executive Officer









Dated:	November 12, 2002	By:	/s/ Thomas E. Legro









			Thomas E. Legro




			Vice President, Controller and




			Chief Accounting Officer

CERTIFICATION OF THOMAS G. BOREN, PRINCIPAL EXECUTIVE OFFICER,
PURSUANT TO SECTION 302 OF THE SARBANES – OXLEY ACT OF 2002

I, Thomas G. Boren, certify that:

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

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

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

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

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

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

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

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

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

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

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


Date: November 12, 2002









		/s/ Thomas G. Boren




		Thomas G. Boren




		President and Chief Executive Officer

CERTIFICATION OF THOMAS E. LEGRO,
PRINCIPAL FINANCIAL OFFICER, PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Thomas E. Legro, certify that:


Date: November 12, 2002









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

	•		A forward contract is a commitment to purchase or sell energy commodities at a specified future date at a specified price.

	•		A futures contract is a standardized commitment, traded on an organized exchange, to purchase or sell an energy commodity or financial instruments at a specified future date and at a specified price.

	•		A swap agreement requires payments for a quantity of an energy commodity based upon the difference between agreed upon prices.

	•		An option contract provides the right, but not the obligation, to buy or sell the underlying commodity at a predetermined price in the future.

	•		The outcome of PG&E NEG’s negotiations with its lenders under PG&E NEG’s revolving credit facilities, the GenHoldings credit facility, the La Paloma and Lake Road credit facilities, and the Equipment Revolver, as well as with representatives of the holders of the Senior Notes, to reach a global restructuring of this debt which would require PG&E NEG to abandon, sell, or transfer certain of PG&E NEG’s merchant assets and reduce trading operations;

	•		The extent to which PG&E NEG incurs a charge to earnings as a result of the abandonment, sale or transfer of assets, whether such transactions occur in connection with the implementation of a global restructuring as may be agreed to by the lenders or otherwise;

	•		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 financial or liquidity constraints, changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others; or by 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 extensions of the maturity date of its revolving credit facility, now due to expire on November 14, 2002, in light of PG&E NEG’s below investment grade credit ratings, liquidity constraints, conditions in the general economy or the energy markets or the capital markets, and the market’s perception of the energy industry;

	•		The results of negotiations with PG&E NEG’s construction lenders to fund completion of certain generating projects beyond November 14, 2002;

	•		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 extent to which counterparties demand collateral in connection with PG&E ET’s trading and nontrading activities which can be affected by the counterparties’ responses to downgrades of PG&E NEG’s and its subsidiaries’ credit ratings, mutual forbearance as many counterparties also have been downgraded, pre- and early-pay arrangements, the continued performance of PG&E NEG companies under the underlying agreements, whether counterparties have the right to demand such collateral, the execution of master netting agreements and offsetting transactions, changes in the amount of the exposure, and the counterparties’ other commercial considerations, and the ability of PG&E NEG and its subsidiaries to meet the liquidity calls that may be made;

	•		The extent to which counterparties seek to terminate tolling agreements based upon the credit downgrades and seek termination damages 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;

	•		The effect of the Utility bankruptcy proceedings upon PG&E Corporation and upon PG&E NEG;

	•		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.

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

	3.		Current Report on Form 8-K filed August 6, 2002

	4.		Current Report on Form 8-K filed August 26, 2002

	5.		Current Report on Form 8-K filed October 10, 2002

	6.		Current Report on Form 8-K filed October 21, 2002

	7.		Current Report on Form 8-K filed October 28, 2002

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

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

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

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

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

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

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

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

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