Pg&e National Energy 10Q/A 2001 Q3 Quarterly report (amended)

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

(Mark one)

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

For the quarterly period ended September 30, 2001

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

For the transition period from ______________ to _____________ .

COMMISSION FILE NO. 333-66032

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


Delaware	7600 Wisconsin Avenue	94-3316236
(State or Other Jurisdiction of	(Mailing address: 7500 Old Georgetown Road)	(I.R.S. Employer
Incorporation or Organization)	Bethesda, Maryland 20814	Identification Number)
	(301) 280-6800
	(Address, Including Zip Code, and Telephone Number,
	Including Area Code, of Registrant’s Principal Executive Offices)

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

Yes No X

PG&E National Energy Group, Inc.
Form 10-Q
For the Quarterly Period ended September 30, 2001
Table of Contents


		Page

PART I.	FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements
	Consolidated Statements of Operations	2
	Consolidated Balance Sheets	3
	Consolidated Statements of Cash Flows	5
	Notes to Consolidated Financial Statements
	Note 1: Organization and Basis of Presentation	6
	Note 2: Relationship with the Parent	6
	Note 3: Accounting Policies	8
	Note 4: Acquisitions and Sales	10
	Note 5: Price Risk Management	11
	Note 6: Short-Term Borrowings and Credit Facilities	12
	Note 7: Long-Term Debt	12
	Note 8: Commitments and Contingencies	13
	Note 9: Segment Information	15

Item 2.	Management’s Discussion and Analysis of Financial Condition and
	Results of Operations	16

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	29

PART II.	OTHER INFORMATION

Item 6.	Exhibits and Reports on Form 8-K	30

Signatures		31

PART I. FINANCIAL INFORMATION

ITEM 1. CONSOLIDATED FINANCIAL STATEMENTS

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


			As Revised, See Note 1							As Revised, See Note 1
			Three Months Ended							Nine Months Ended
			September 30,							September 30,

			2001				2000			2001				2000

OPERATING REVENUES:
	Generation, transportation, and trading			$	3,343		$	5,122			$	10,253		$	11,771
	Equity in earnings of affiliates				18			16				67			53

		Total operating revenues			3,361			5,138				10,320			11,824

OPERATING EXPENSES:
	Cost of commodity sales and fuel				3,041			4,800				9,362			10,877
	Operations, maintenance, and management				126			176				394			513
	Administrative and general				15			12				51			38
	Depreciation and amortization				45			35				120			105
	Other				(2	)		22				47			6

		Total operating expenses			3,225			5,045				9,974			11,539

OPERATING INCOME					136			93				346			285

OTHER INCOME (EXPENSES):
	Interest Income				23			27				72			61
	Interest Expense				(48	)		(40	)			(106	)		(118	)
	Other income (expense)—net				(4	)		(5	)			2			(14	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES					107			75				314			214
	Income tax expense				30			32				112			87

INCOME FROM CONTINUING OPERATIONS					77			43				202			127
DISCONTINUED OPERATIONS:
	Loss on disposal of PG&E Energy Services, net of applicable income tax benefit of $13 million				—			(19	)			—			(19	)

NET INCOME				$	77		$	24			$	202		$	108

The accompanying notes are an integral part of these Consolidated Financial Statements.

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


					As Revised, See Note 1			As Revised, See Note 1
					September 30,			December 31,
					2001			2000

				ASSETS
CURRENT ASSETS:
	Cash and cash equivalents				$	726		$	738
	Restricted cash					152			79
	Accounts receivable, customers (net of allowance for uncollectibles of $43 million and $19 million, respectively)					1,202			2,468
	Other receivables					204			159
	Note receivable from Parent					—			75
	Inventory					118			112
	Price risk management					152			2,039
	Prepaid expenses, deposits, and other					149			474

			Total current assets			2,703			6,144

PROPERTY, PLANT, AND EQUIPMENT:
	Property, plant, and equipment in service					4,444			3,747
	Accumulated depreciation					(856	)		(757	)

						3,588			2,990
	Construction work in progress					1,806			1,355

		Total property, plant, and equipment—net				5,394			4,345

OTHER NONCURRENT ASSETS:
	Long-term receivables					476			536
	Long-term receivables from Parent					153			—
	Investments in unconsolidated affiliates					419			417
	Goodwill, net of accumulated amortization of $29 million and $25 million, respectively					94			100
	Price risk management					52			2,026
	Other					494			399

		Total other noncurrent assets				1,688			3,478

TOTAL ASSETS					$	9,785		$	13,967

The accompanying notes are an integral part of these Consolidated Financial Statements.

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


					As Revised, See Note 1			As Revised, See Note 1
					September 30,			December 31,
					2001			2000

				LIABILITIES AND STOCKHOLDER’S EQUITY
CURRENT LIABILITIES:
	Short-term borrowings				$	319		$	519
	Long-term debt—current					48			17
	Obligations due to Parent					309			309
	Accounts payable:
		Trade				1,031			2,210
		Related parties				36			156
	Accrued expenses					380			288
	Price risk management					52			1,999
	Out-of-market contractual obligations					123			141
	Other					56			241

			Total current liabilities			2,354			5,880

NONCURRENT LIABILITIES:
	Long-term debt					3,278			2,204
	Deferred income taxes					715			792
	Price risk management					33			1,867
	Out-of-market contractual obligations					711			800
	Long-term advances from Parent					118			—
	Other liabilities and deferred credits					38			45

			Total noncurrent liabilities			4,893			5,708

MINORITY INTEREST						19			18
COMMITMENTS AND CONTINGENCIES (Note 8)						—			—
PREFERRED STOCK OF SUBSIDIARY						57			57
STOCKHOLDER’S EQUITY:
	Capital stock, $1.00 par value—1,000 shares issued and outstanding					—			—
	Paid-in capital					3,086			3,086
	Accumulated deficit					(579	)		(781	)
	Accumulated other comprehensive loss					(45	)		(1	)

			Total stockholder’s equity			2,462			2,304

TOTAL LIABILITIES AND STOCKHOLDER’S EQUITY					$	9,785		$	13,967

The accompanying notes are an integral part of these Consolidated Financial Statements.

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


				As Revised, See Note 1
				Nine Months Ended
				September 30,

					2001				2000

CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income					$	202			$	108
	Adjustments to reconcile net income:
		Depreciation and amortization					120				105
		Deferred income taxes					(77	)			26
		Amortization of out-of-market contractual obligation					(107	)			(124	)
		Other deferred credits and noncurrent liabilities					(6	)			(37	)
		Gain on sale of assets					—				(21	)
		Loss from discontinued operations					—				19
		Equity in earnings of affiliates					(67	)			(53	)
		Distribution from affiliates					49				81
	Net effect of changes in working capital assets and liabilities:
		Restricted cash					(73	)			13
		Accounts receivable—customers					1,256				(629	)
		Inventories, prepaids and deposits					200				(136	)
		Price risk management					34				15
		Accounts payable and accrued expenses					(1,212	)			554
		Accounts payable—related parties					5				18
		Other—net					(8	)			120

			Net cash provided by operating activities				316				59

CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures						(1,059	)			(681	)
	Acquisition of assets						(92	)			(311	)
	Proceeds from sale of assets (equity investments)						—				132
	Prepayments on generating assets						(144	)			(110	)
	Long-term receivable						60				56
	Other—net						70				(201	)

			Net cash used in investing activities				(1,165	)			(1,115	)

CASH FLOWS FROM FINANCING ACTIVITIES:
	Net borrowings (repayments) under credit facilities						(200	)			141
	Long-term debt issued						703				752
	Bonds issuance, net of discount and issuance costs						972				—
	Long-term debt matured, redeemed, or repurchased						(638	)			(212	)
	Advances from Parent						—				256
	Capital contributions						—				223
	Distributions						—				(103	)

			Net cash provided by financing activities				837				1,057

NET CHANGE IN CASH AND CASH EQUIVALENTS							(12	)			1
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD							738				228

CASH AND CASH EQUIVALENTS, END OF PERIOD						$	726			$	229

SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
	Cash paid for:
		Interest—net of amount capitalized				$	118			$	134
		Income taxes—net of refunds					(8	)			(13	)
SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING:
	Reclassification of short-term Parent receivables to long-term						153				—
	Reclassification of demand notes payable to Parent from short-term to long-term						118				—
	Note receivable forgiven by NEG to Parent						—				(25	)
	Change in other comprehensive income due to SFAS 133						65				—
	Change in deferred income taxes due to SFAS 133						(23	)			—
	Long-term debt related to a subsidiary						(40	)			(82	)

The accompanying notes are an integral part of these Consolidated Financial Statements.

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

NOTE 1. 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 (“Parent”). Shortly thereafter, the Parent contributed various subsidiaries to the PG&E National Energy Group, Inc. PG&E National Energy Group, Inc., and its subsidiaries (collectively, “NEG”, or the “Company”) 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. The Company’s principal subsidiaries include: PG&E Generating Company, LLC, and its subsidiaries (collectively, “GenLLC”); PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, “Energy Trading” or “ET”); PG&E Gas Transmission Corporation and its subsidiaries (collectively, “GTC”), which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively, “GTN”). Other subsidiaries of GTC, PG&E Gas Transmission, Texas Corporation and subsidiaries, and PG&E Gas Transmission Teco, Inc. and subsidiaries (collectively “GTT”) were sold in December 2000. See Note 4 for a discussion of the sale of GTT. PG&E Energy Services Corporation (“ES”), which was discontinued in 1999, provided retail energy services. NEG also has other less significant subsidiaries. See Note 2 for a discussion on a corporate restructuring, known as “ringfencing”.

The Company believes that the accompanying unaudited Consolidated Financial Statements reflect all adjustments that are necessary to present a fair statement of the consolidated financial position and results of operations for the interim periods. All material adjustments are of a normal recurring nature unless otherwise disclosed in this Form 10-Q/A. All unaudited significant intercompany transactions have been eliminated from the Consolidated Financial Statements.

Certain amounts in the prior year’s unaudited Consolidated Financial Statements may have been reclassified to conform to the 2001 presentation. Results of operations for interim periods are not necessarily indicative of results to be expected for a full year.

This quarterly report should be read in conjunction with the Consolidated Financial Statements and Notes to Consolidated Financial Statements incorporated by reference in the Company’s registration statement on Form S-4 filed with the Securities and Exchange Commission on July 27, 2001 and amended on August 21, 2001.

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.

Subsequent to the issuance of NEG’s September 30, 2001 Form 10-Q consolidated financial statements, management determined that the assets and liabilities relating to certain leases should have been consolidated. The facilities associated with the leases were under construction during 2001 and 2000. A summary of the significant effects of the revisions to the Consolidated Statements of Operations, Consolidated Balance Sheets, and Consolidated Statements of Cash Flows is as follows (in millions):


		2001						2000

		As						As
		Previously			As			Previously			As
		Reported			Revised			Reported			Revised

Three Months Ended September 30:
CONSOLIDATED STATEMENTS OF OPERATIONS
Generation, transportation, and trading			3,346			3,343			5,124			5,122
	Total operating revenues		3,364			3,361			5,140			5,138

Operations, maintenance, and management			129			126			178			176
	Total operating expenses		3,228			3,225			5,047			5,045

Nine Months Ended September 30:
Generation, transportation, and trading			10,261			10,253			11,780			11,771
	Total operating revenues		10,328			10,320			11,833			11,824

Operations, maintenance, and management			402			394			522			513
	Total operating expenses		9,982			9,974			11,548			11,539

At September 30, 2001 and December 31, 2000, respectively:
CONSOLIDATED BALANCE SHEETS
Restricted cash			108			152			53			79
Accounts receivable and Other receivables			1,407			1,406			2,629			2,627
Prepaid expenses, deposits, and other			148			149		no change			no change
	Total current assets		2,659			2,703			6,120			6,144

Construction work in progress			735			1,806			650			1,355
	Total property, plant and equipment — net		4,323			5,394			3,640			4,345

Other Noncurrent assets		no change			no change				267			399

TOTAL ASSETS			8,670			9,785			13,106			13,967

Accounts payable — Trade			982			1,031			2,170			2,210
Accrued expenses			373			380			281			288
Other current liabilities			57			56		no change			no change
	Total current liabilities		2,299			2,354			5,833			5,880

Long-term debt			2,218			3,278			1,390			2,204
	Total noncurrent liabilities		3,833			4,893			4,894			5,708

TOTAL LIABILITIES AND COMMON STOCKHOLDER’S EQUITY			8,670			9,785			13,106			13,967

Nine Months Ended September 30:
CONSOLIDATED STATEMENTS OF CASH FLOWS
Capital expenditures			(693	)		(1,059	)		(210	)		(681	)
Long-term debt issued			457			703			194			752

NOTE 2. RELATIONSHIP WITH THE PARENT

For periods prior to 2001, the Parent provided financial support in the form of direct lending activities with the Company and collateral to third parties to support the Company’s contractual commitments and daily operations. Funds from operations were managed through net investments or borrowings in a pooled cash management arrangement, and the Parent provided credit support for trading activities through Parent guarantees and surety bonds. Certain development and construction activities were funded in part through Parent equity contributions or secured using instruments such as Parent guarantees or equity commitments. As of December 31, 2000, Parent guarantees to third parties for trading and structured tolling arrangements totaled $2.4 billion and Parent equity funding commitments for construction activities totaled $1 billion. The Parent also assisted with financing activities through short-term demand borrowings and long-term notes between the Parent and the Company and Parent guarantees of certain minor credit facilities. Furthermore, the Company, the Parent and another affiliate of the Parent share the costs of certain administrative and general functions.

The Parent’s financial condition in the past had a direct operational and financial impact on the Company. The Parent’s credit rating affected the value of the Parent guarantees supporting the Company’s trading, development and construction activities. The Parent experienced liquidity and credit problems as a result of financial difficulties at another subsidiary, the California public utility Pacific Gas and Electric Company (the “Utility”). Under the deregulated wholesale power market in California, the Utility’s wholesale power purchase costs have

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

exceeded revenues provided by frozen retail electric rates, resulting in undercollected purchased power costs of approximately $6.6 billion at December 31, 2000. In January 2001, the major credit rating agencies downgraded the Parent’s credit ratings to below investment grade, in some cases entitling the Company’s counterparties to demand substitute credit support. In addition, under the Parent’s equity funding commitment agreements that supported the Company’s operations and construction activities, the downgrade and the subsequent failure by the Parent to provide an acceptable letter of credit in the required amounts within the required time periods would have triggered the Parent’s obligation to infuse the required amounts of capital. Failure by the Parent to meet its equity commitments would have constituted a default under these agreements. Furthermore, the Parent defaulted on certain debt payments and suspended its quarterly dividends.

On March 2, 2001, the Parent refinanced its outstanding commercial paper and bank borrowings with the $1 billion proceeds from two term loans (the “New Parent Debt”) borrowed under a common credit agreement with General Electric Capital Corporation and Lehman Commercial Paper, Inc. (the “Lenders”). Under the New Parent Debt agreement, the Parent has given the Lenders a security interest in the Parent’s ownership in the Company and an option to purchase 2 to 3 percent of the shares of NEG at an exercise price of $1.00. This option becomes exercisable upon the date of full repayment of the New Parent Debt or earlier, if an initial public offering (“IPO”) of the shares of NEG were to occur. Any net proceeds from an IPO of NEG must first be used to reduce the outstanding balance of the New Parent Debt to $500 million or less. Among other things, the covenants of the New Parent Debt require that NEG maintain an investment grade credit rating for its unsecured long-term debt.

The Company and its Parent have completed a corporate restructuring of the NEG, known as a “ringfencing” transaction. The ringfencing involved the creation of new special purpose entities (SPEs) as intermediate owners between the Parent and its NEG subsidiaries. These new SPEs are PG&E National Energy Group, LLC, which owns 100% of the stock of the NEG; GTN Holdings LLC, which owns 100% of the stock of GTN; and PG&E Energy Trading Holdings LLC, which owns 100% of the stock of ET. In addition, NEG’s organizational documents were modified to include the same structural elements as the SPEs. The SPEs require unanimous approval of their respective boards of directors, which include an 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 SPEs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements. After the ringfencing structure was implemented, two independent rating agencies, Standard & Poor’s (S&P) and Moody’s Investor Services reaffirmed investment grade ratings for GTN and GenLLC, and issued investment grade ratings for NEG. S&P also issued an investment grade rating for ET.

On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. 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. On September 20, 2001, the Utility and Parent jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The plan of reorganization does not directly affect the Company or any of its subsidiaries.

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

As of September 30, 2001, the Company had replaced or eliminated nearly all of the Parent guarantees with respect to the Company’s trading operations with a combination of guarantees provided by the Company or its subsidiaries and letters of credit obtained independently by the Company. As of September 30, 2001, only one Parent guarantee in the amount of $8 million remained outstanding, with no related exposure to the Parent. In addition, the Company had also negotiated substitute equity commitments with certain third parties to construction financing agreements, replacing the $1 billion of Parent guarantees and equity commitments under the construction financing agreements.

As of September 30, 2001, Attala Power Corporation (“APC”), an indirect wholly-owned subsidiary of the Company, has a non-recourse demand note payable to the Parent of $309 million and GTN has a note receivable

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

from the Parent of $75 million. The APC note is classified as short-term and the GTN note is classified as long-term on the consolidated balance sheet, as of September 30, 2001. The demand note between APC and the Parent is recourse only to the assets of APC and not to the Company.

In addition, as of September 30, 2001, other wholly-owned subsidiaries of the Company had net amounts payable in the amount of $122 million in the form of promissory notes to the Parent related primarily to past funding of generating asset development and acquisition, of which $118 million was classified as long-term on the consolidated balance sheet. Furthermore, as of September 30, 2001, the Company has recorded a $78 million amount receivable from the Parent related to the intercompany tax-sharing arrangement; this amount is included in “Long-term receivables from Parent”, as of September 30, 2001, in the accompanying consolidated balance sheet. With the exception of these intercompany balances, the Company has terminated its intercompany borrowing and cash management programs with the Parent and settled its outstanding balances due to or from the Parent. Management of the Company believes that it will be able to meet its short-term obligations and fund growth and operations through retained earnings, third-party borrowing facilities or other strategies.

NOTE 3. ACCOUNTING POLICIES

Accounting for Derivative Instruments—The Company adopted Statement of Financial Accounting Standards (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138 (collectively, the “Statement”), on January 1, 2001. The Statement requires the Company to recognize all derivatives, as defined in the Statement, on the balance sheet at fair value. Effective January 1, 2001, derivatives are classified as price risk management assets and liabilities. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income until the hedged items are recognized in earnings. The Company has several types of derivatives designated as cash flow hedges, including interest rate swaps used to hedge interest payments on variable-rate debt and forward contracts, futures and swaps used to hedge energy commodity price risk and foreign currency swaps as hedges of exchange rate risk.

The Company also has certain derivative commodity contracts for the physical delivery of purchase and sale quantities transacted in the normal course of business. In June 2001 (as revised in October 2001), the Financial Accounting Standards Board (“FASB”) approved an interpretation issued by the Derivatives Implementation Group (“DIG”) that changes the definition of normal purchases and sales for certain power contracts. The Company must implement this interpretation on January 1, 2002, and is currently assessing the impact of these new rules. The FASB has also approved another DIG interpretation that disallows normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Certain of the Company’s derivative commodity contracts may no longer be exempt from the requirements of the Statement. The Company is evaluating the impact of this implementation guidance on its financial statements, and will implement this guidance, as appropriate, by the implementation deadline of April 1, 2002.

The Company’s transition adjustment to implement this new standard was an immaterial adjustment to net income and a negative adjustment of $333 million (after-tax) to other comprehensive income, a component of stockholder’s equity. This transition adjustment, which relates to hedges of interest rate, foreign currency and commodity price risk exposure, was recognized as of January 1, 2001, as a cumulative effect of a change in accounting principle.

Net gains and losses on derivative instruments recognized in earnings for the three and nine months ended September 30, 2001 were classified in various captions, including operating revenues, cost of commodity sales and fuel and interest expense.

As of September 30, 2001, the maximum length of time over which the Company has hedged its exposure to the variability in future cash flows associated with commodity price risk is through December 2005.

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Property, Plant, and Equipment—Property, plant, and equipment is recorded at cost, which includes costs of purchased equipment, related labor and materials, and interest during construction. Property, plant, and equipment purchased as part of an acquisition are reflected at fair value on the acquisition date. These capitalized costs are depreciated on a straight-line basis over estimated useful lives, less any residual or salvage value. Routine maintenance and repairs are charged to expense as incurred.

Property, plant, and equipment consists of the following (in millions):


		September 30,			December 31,
	Estimated Lives	2001			2000

Electric generating facilities	20 to 50 years	$	2,617		$	1,955
Gas transmission	15 to 40 years		1,486			1,477
Other	2 to 20 years		211			190
Land			130			125

			4,444			3,747
Less: Accumulated depreciation			(856	)		(757	)

Property, plant, and equipment—net			3,588			2,990
Construction in progress			1,806			1,355

		$	5,394		$	4,345

Out-of-Market Contractual Obligations—Commitments contained in the underlying Power Purchase Agreements (“PPAs”), gas commodity and transportation agreements (collectively, the “Gas Agreements”), and Standard Offer Agreements, were recorded at fair value, based on management’s estimate of either or both the gas commodity and gas transportation markets and electric markets over the life of the underlying contracts, discounted at a rate commensurate with the risks associated with such contracts. Standard Offer Agreements reflect a commitment to supply electric capacity and energy necessary for certain New England Electric System (“NEES”) affiliates to meet their obligations to supply fixed-rate service. PPAs and Gas Agreements are amortized on a straight-line basis over their specific lives. The Standard Offer Agreements are amortized using an accelerated method since the decline in value is greater in earlier years due to increasing contract pricing terms reducing the obligation to supply service over time. The carrying value of the out-of-market obligations is as follows (in millions):



	Amortization	September 30,		December 31,
	Period	2001		2000

PPAs	1–20 years	$	556	$	599
Gas Agreements	8–13 years		176		188
Standard Offer Agreements	6–7 years		102		154

			834		941
Less: Current portion			123		141

Long-term portion		$	711	$	800

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

Income Taxes—The Company accounts for income taxes under the liability method. Deferred tax assets and liabilities are determined based on the difference between financial statement carrying amounts and tax basis of assets and liabilities, using currently enacted tax rates. The Company’s effective tax rate was lower for the nine months ended September 30, 2001, as compared to prior years mainly due to IRS Section 29 tax credits.

The Company and its subsidiaries are included in the federal consolidated tax return of the Parent. The Company and its subsidiaries have a tax-sharing arrangement with the Parent that provides for the allocation of federal and certain state income taxes. In consideration of the Company’s participation in such consolidated return and the tax-sharing arrangement, the Company recognized its pro rata share of consolidated income tax expenses and benefits. The Company was allowed to use the tax benefits generated as long as these benefits could be used on a consolidated basis. Certain states require that each entity doing business in that state file a separate tax return (the “Separate State Taxes”). Canadian subsidiaries are subject to Canadian federal and provincial income taxes based on net income (the “Canadian Taxes”). Tax consequences of the Separate State Taxes and the Canadian Taxes are excluded from the tax-sharing arrangement and thus are separately accounted for by the Company. Beginning with the 2001 calendar year, the Company expects to pay to the Parent the amount of income taxes that the Company would be liable for if the Company filed its own consolidated combined or unitary return separate from the Parent, subject to certain consolidated adjustments.

New Accounting Pronouncements—In June 2001, the FASB issued SFAS No. 141,Business Combinations. This standard prohibits the use of the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. The Company does not expect that implementation of this standard will have a significant impact on its financial statements.

Also in June 2001, the FASB issued SFAS No. 142,Goodwill and Other Intangible Assets. This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. This standard also requires the useful lives of previously recognized intangible assets to be reassessed and the remaining amortization periods to be adjusted accordingly. This standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on the Company’s balance sheet at that date, regardless of when the assets were initially recognized. The Company is assessing the impact of this standard on its financial statements.

In July 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations. This standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets. The Company has not yet determined the effects of this standard on its financial statements.

In October 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets.SFAS No. 144 supercedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,but retains its fundamental provisions 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 are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should cease to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, superceding previous guidance for discontinued operations of business segments. This Statement is effective for fiscal years beginning after December 15, 2001. The Company is assessing the impact of this standard on its financial statements.

NOTE 4. ACQUISITIONS AND SALES

On January 27, 2000, the Company signed a definitive agreement with El Paso Field Services Company (“El Paso”) providing for the sale to El Paso, a subsidiary of El Paso Energy Corporation, of the stock of GTT. Given the terms of the sales agreement, in 1999 the Company recognized a charge against pre-tax earnings of $1,275 million, to reflect GTT’s assets at their fair value. On December 22, 2000, after receipt of governmental approvals, the Company completed the stock sale. The total consideration received was $456 million, less $150 million used to retire the GTT short-term debt, and the assumption by El Paso of GTT long-term debt having a book value of

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

$564 million. The final sales price, which is subject to a working capital true-up adjustment, is expected to be finalized in the fourth quarter of 2001, with the amount expected to be immaterial. GTT’s total assets and liabilities, including the charge noted above, are included in the Company’s Consolidated Balance Sheets through the date the sale was completed.

On September 28, 2000, the Company, through its indirect subsidiary APC, purchased for $311 million the Attala Generating Company, LLC, which owned a gas-fired power plant then under construction. Under the purchase agreement, the Company prepaid the estimated remaining construction costs, which were being managed by the seller. The project began commercial service in June 2001. In connection with the acquisition, the Company also assumed industrial revenue bonds in the amount of $159 million. The seller has agreed to pay off the bonds prior to December 15, 2001; accordingly, the Company has recorded a receivable equal to the amount of the outstanding bonds and accrued interest at September 30, 2001.

On June 29, 2001, the Company contracted to supply the full service power requirements of the city of Denton, Texas, for a period of five years beginning July 1, 2001. The city of Denton’s peak load forecast is 272 megawatts in 2001, increasing to 314 megawatts over the contract term. The Company’s supply obligation to the city is net of approximately 97 megawatts of generation entitlements retained by the city, plus 40 megawatts of purchased power that the city has assigned to the Company for the summer of 2001. In connection with the power supply agreement, the Company acquired a 178-megawatt generating station and has agreed to acquire two small hydroelectric facilities from the city. Total consideration of approximately $12 million was allocated between the fair value of the power supply contract, recorded as an intangible asset, and property, plant and equipment.

On July 10, 2001, the Company completed the sale of certain development assets, resulting in a gain of $23 million. On September 17 and 28, 2001, the Company purchased Mountain View Power Partners, LLC and Mountain View Power Partners II, LLC, respectively. These companies own 44.4 and 22.2 megawatt wind energy projects, respectively, near Palm Springs, California. The Company has contracted with SeaWest for the operation and maintenance of the wind units and will sell the entire output of the two wind projects, under a long-term contract. Total consideration for these two companies was $92 million.

NOTE 5. PRICE RISK MANAGEMENT

The Company’s net gains (losses) on trading contracts for the three and nine months ended September 30, 2001 were $44.4 million and $165.6 million, respectively.

Quantitative Information About Cash Flow Hedges—As described in Note 3, the Company adopted SFAS No. 133 on January 1, 2001. The Company’s cash flow hedges, recorded in accordance with SFAS No. 133, include hedges of commodity price risk and interest rate. The Company’s ineffective portion of changes in fair values of cash flow hedges is immaterial for the three- and nine-month periods ended September 30, 2001. The Company expects that net derivative losses of $39 million included in Accumulated other comprehensive loss as of September 30, 2001, will be reclassified into earnings within the next twelve months.

The table below summarizes the effect of derivative activities on Accumulated other comprehensive loss, net of tax, for the three and nine months ended September 30, 2001 (in millions).

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)


	Three months ended			Nine months ended
	September 30, 2001			September 30, 2001

Beginning Accumulated other comprehensive loss at July 1, 2001 and January 1, 2001, respectively	$	(65	)	$	(333	)
Net gain from current period hedging transactions and price changes		20			176
Net reclassification to earnings		3			115

Ending accumulated derivative net loss at September 30, 2001		(42	)		(42	)
Foreign currency translation adjustment		(3	)		(3	)

Ending Accumulated other comprehensive loss at September 30, 2001	$	(45	)	$	( 45	)

As of September 30, 2001, the maximum length of time over which the Company has hedged exposure to the variability in future cash flows associated with commodity price risk is through December 2005.

Credit Risk—The use of physical and financial instruments to manage the risks associated with changes in commodity prices creates exposure resulting from the possibility of nonperformance by counterparties pursuant to the terms of their contractual obligation. The counterparties in the Company’s portfolio consist primarily of investor-owned and municipal utilities, energy trading companies, financial institutions, and coal, oil and gas production companies. The Company minimizes credit risk by dealing primarily with creditworthy counterparties in accordance with established credit approval practices and limits. The Company assesses the financial strength of its counterparties at least quarterly and requires that counterparties post security in forms of cash, letters of credit, corporate guarantees of acceptable credit quality, or eligible securities if current net receivables and replacement cost exposure exceeds contractually specified limits. The Company did not experience any material losses due to the non-performance of counterparties during the three- and nine-month periods ended September 30, 2001. At September 30, 2001, the Company’s gross credit risk exposure amounted to $787 million. Counterparties considered to be investment grade or higher comprise 77% of the total credit exposure.

NOTE 6. SHORT-TERM BORROWINGS AND CREDIT FACILITIES

On June 15, 2001, the Company entered into a $550 million revolving credit facility to support energy trading operations and other Company working capital requirements. This facility, which has an initial term of 364 days, provides for bank borrowings and letters of credit. Borrowings under the facility bear interest based on LIBOR plus an applicable margin of 1.75%. On August 23, 2001, this facility was increased to $1.25 billion. The Company is required to comply with certain financial covenants, including a minimum ratio of cash flow to fixed charges of 1.5 to 1.0 and a maximum ratio of debt to capitalization of 0.6 to 1.0. At September 30, 2001, $156 million of letters of credit were outstanding under this facility and borrowings of $295 million were outstanding under this facility.

On June 18, 2001, the Company reduced one of its $550 million revolving credit facilities at GenLLC to $500 million to meet the requirements of the new facility, described above. On August 23, 2001, this facility and another $550 million 5-year revolving credit facility at GenLLC were cancelled.

Also, on May 29, 2001, a subsidiary of the Company entered into a revolving credit facility of up to $280 million. Borrowings under this facility were used to purchase all turbines from the two master turbine trusts (see Note 8) and will be used to fund future turbine payments and equipment purchases associated with the development of our generating facilities. This facility, which expires on December 31, 2003, provides for bank borrowings. Borrowings under the facility bear interest based on LIBOR plus a credit spread.

NOTE 7. LONG-TERM DEBT

On May 22, 2001, the Company issued senior notes in an aggregate principal amount of $1 billion. These notes, which mature on May 16, 2011, bear interest at 10.375% and require semiannual interest payments on May 15 and November 15. The Company has the option to redeem any or all of the notes before maturity at the greater of the outstanding principal balance or an amount equal to the present value of remaining principal and

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

interest due on the notes, discounted using the rate on a United States Treasury Security of comparable maturity plus 50 basis points, in either case plus accrued interest. The notes, which are senior obligations of PG&E National Energy Group, Inc. and rank on a pari passu with borrowings under the Company’s new $1.25 billion revolving credit facility, are subordinated to indebtedness of the Company’s subsidiaries. The notes received investment grade credit ratings from Standard & Poor’s and Moody’s. The indenture for the senior notes contains cross-default provisions that provide that an event of default under any instrument that secures or evidences indebtedness of the Company in excess of $50 million, which event of default results in the acceleration of such indebtedness, constitutes an event of default under the senior notes. On July 27, 2001, the Company registered the bonds in an S-4 registration with the U.S. Securities and Exchange Commission and commenced an exchange offer to allow the senior note holders to exchange their senior notes for exchange notes with substantially similar terms as the senior notes. The senior notes were exchanged by October 1, 2001 to exchange notes.

The Company has used a portion of the proceeds and intends to use the balance of the senior notes issuance, net of $28 million of debt discount and note issuance costs, to pay down existing revolving debt, fund investments in generating facilities and pipeline assets, working capital requirements and other general corporate requirements.

On September 6, 2001, a subsidiary of the Company entered into a Credit agreement for $69.4 million. The debt facility will be used to fund construction of the Plains End project. This facility expires upon the earlier of five years after commercial operations has been declared or September 30, 2007. The facility provides for borrowings that bear interest based on LIBOR plus a credit spread. On September 19, 2001 and September 27, 2001, the subsidiary executed accreting and amortizing interest rate swaps and forwards to hedge approximately 80% of loans expected to be drawn.

The Company had entered into agreements with a trust that would have owned and financed turbine payments and project related costs for the Harquahala facility. In the third quarter, the Company decided not to pursue a post construction operating lease facility. Consequently, the Company began to directly fund the construction of this project with its own resources and began to consolidate the special purpose entity. The construction costs of $120 million are classified as Construction work in progress and the borrowings in the amount of $120 million are classified as Long-term debt.

Subsequent to the issuance of the Company’s 1999 and 2000 consolidated financial statements, management determined that the assets and liabilities relating to certain leased facilities should have been consolidated. The credit facilities outstanding as of September 30, 2001, were approximately $940 million at an average weighted interest rate of approximately 6.6%, relating the Lake Road and the La Paloma projects. These nonrecourse facilities have terms through 2018 and 2022 for Lake Road and La Paloma, respectively. The Company has committed to project lenders to contribute equity of up to $230 million for Lake Road and $379 million for La Paloma through the purchase of the portion of project loans no later than March 31, 2003. The equity infusions could be triggered earlier by a downgrade of NEG below investment grade from both S&P and Moodys or the failure to meet certain debt covenants of either project.

NOTE 8. COMMITMENTS AND CONTINGENCIES

Legal Matters—The Company is involved in various litigation matters in the ordinary course of its business.

Energy Trading Litigation—A creditor’s involuntary bankruptcy petition was filed in August 1998 against a power marketing entity. ET is an unsecured creditor of this entity. As part of the bankruptcy, the bankruptcy court created a liquidating trust (the “Trust”) and appointed a trustee to act on behalf of the Trust. The trustee has alleged, among other things, that ET improperly terminated transactions with the bankrupt power marketer. In December 1999, ET filed an action in federal court in Texas (“Texas Action”) seeking a declaration from the court that termination of the transactions with the bankrupt power marketer was not a breach of the agreements. Subsequently, the trustee filed suit in the bankruptcy court (“Bankruptcy Action”) alleging, among other things, breach of contract, various torts, unjust enrichment, improvement in position, and preference. The lawsuit seeks approximately $32 million in actual damages, plus punitive damages in an unspecified amount. The parties have agreed to dismiss the Texas Action and the Bankruptcy Action without prejudice. In August 2001, the parties entered into a settlement agreement under which ET will pay $3 million to the bankruptcy estate and both parties will dismiss with prejudice all litigation in connection with this matter. On September 25, 2001, the settlement agreement was submitted to the bankruptcy court for approval, which approval was granted on October 17, 2001.

Other Litigation—The Company and/or its subsidiaries are parties to additional claims and legal proceedings arising in the ordinary course of business. The Company believes it is unlikely that the final outcome of these other claims would have a material adverse effect on the Company’s financial statements.

Environmental Matters—In May 2000, the Company 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 the Company to provide certain information, relative to the compliance of the Company’s Brayton Point and Salem Harbor Generating Stations with the CAA. No enforcement action has been brought by the EPA to date. The Company has had very preliminary discussions with the EPA to explore a potential settlement of this matter. As a result of this and related regulatory initiatives by the Commonwealth of Massachusetts, the Company is exploring initiatives that would assist the Company to achieve significant reductions of sulfur dioxide and nitrogen oxide emissions by as early as 2006 to 2010. Management believes that the Company would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants and estimates that capital expenditures on these environmental projects will be approximately $265 million through

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

2006. 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.

GenLLC’s existing power plants, including USGen New England, Inc. (“USGenNE”) facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to National Pollutant Discharge Elimination System (“NPDES”), permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and it is anticipated that all three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. It is estimated that USGenNE’s cost to comply with the new permit conditions could be as much as $60 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits.

In September 2000, the Company settled a legal claim through certain agreements that require the Company to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. The Company began the activities during 2000 and is expected to complete them in 2002 as the review and permitting process with the State has caused some delays. In addition to costs incurred in 2000, at December 31, 2000, the Company recorded a reserve in the amount $3.2 million relating to its estimate of the remaining environmental expenses to fulfill its obligations under the agreement. In addition, the Company expects to incur approximately $4 million in capital expenditures during 2001 and into 2002 to complete the project.

Turbine and Construction Commitments—On May 31, 2001, the Company terminated the agreements covered by the operative documents executed on September 8, 2000, to facilitate the development, construction and financing of several power generation projects. Using borrowings from the newly-arranged $280 million revolving credit facility (see Note 6), the Company prepaid the turbine commitments. The prepaid turbine commitments, as of September 30, 2001, totaled $276 million and is recorded as Other noncurrent assets.

Financing Commitment—In May 2001, the Company extended a contingent financing commitment to the owner of a project for which the Company has executed a tolling agreement. The Company committed to provide a subordinated loan of up to $75 million to the project owner at the time of completion of the project, if at that time the Company does not meet certain credit rating criteria as agreed upon with the counterparty to the tolling contract.

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

NOTE 9. SEGMENT INFORMATION

The Company is currently managed under two reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distribution and regulatory environment, and how information is reported to key decision makers. The first business segment is composed of the 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 the NEG’s Interstate Pipeline Operations. See Note 4 for more discussion of the sale of GTT from the Interstate Pipeline Operations. Segment information for the three and nine months ended September 30, 2001 and 2000 was as follows (in millions):


	Integrated
	Energy and		Interstate
	Marketing		Pipeline		Other and
	Activities		Operations		Eliminations			Total

Three Months Ended September 30, 2001 Operating revenues	$	3,294	$	57	$	(8	)	$	3,343
Equity in earnings of affiliates		18		—		—			18

Total operating revenues		3,312		57		(8	)		3,361

Income from continuing operations		64		19		(6	)		77
Net income		64		19		(6	)		77

Three Months Ended September 30, 2000 Operating revenues	$	4,798	$	322	$	2		$	5,122
Equity in earnings of affiliates		16		—		—			16

Total operating revenues		4,814		322		2			5,138

Income from continuing operations		25		16		2			43
Net income		25		16		(17	)		24

Nine Months Ended September 30, 2001 Operating revenues	$	10,071	$	186	$	(4	)	$	10,253
Equity in earnings of affiliates		67		—		—			67

Total operating revenues		10,138		186		(4	)		10,320

Income from continuing operations		152		57		(7	)		202
Net income		152		57		(7	)		202

Nine Months Ended September 30, 2000 Operating revenues	$	10,884	$	884	$	3		$	11,771
Equity in earnings of affiliates		53		—		—			53

Total operating revenues		10,937		884		3			11,824

Income from continuing operations		81		43		3			127
Net income		81		43		(16	)		108

Total assets at September 30, 2001	$	8,447	$	1,198	$	140		$	9,785
Total assets at September 30, 2000		8,425		2,350		305			11,080

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

This Quarterly Report on Form 10-Q includes forward-looking statements. We have based these forward-looking statements on our current expectations and projections about future events based upon our knowledge of facts as of the date of this Quarterly Report on Form 10-Q and our assumptions about future events. These forward-looking statements are subject to various risks and uncertainties that may be outside our control including, among other things:

	•		the direct and indirect effects of the current California energy crisis on us, including the measures adopted and being contemplated by federal and state authorities to address the crisis;

	•		the effect of the Pacific Gas and Electric Company bankruptcy proceedings upon our parent, PG&E Corporation (the “Parent”), and upon us;

	•		fluctuations in commodity fuel and electricity prices and any resulting increases in the cost of producing power and/or decreases in prices of power we sell, and our ability to manage such fluctuations and changing prices;

	•		illiquidity in the commodity energy market;

	•		legislative and regulatory initiatives regarding deregulation and restructuring of the electric and natural gas industries in the United States;

	•		the pace and extent of the restructuring of the electric and natural gas industries in the United States;

	•		the extent and timing of the entry of additional competition into the power generation, energy marketing and trading and natural gas transmission markets;

	•		our pursuit of potential business strategies, including acquisitions or dispositions of assets or internal restructuring;

	•		the extent to which our current or planned development of generating facilities, pipelines and storage facilities are completed and the pace and cost of that completion, including the extent to which commercial operations of these development projects are delayed or prevented because of various development and construction risks such as the failure to obtain necessary permits or equipment, the failure of third party contractors to perform their contractual obligations, or the failure of necessary equipment to perform as anticipated;

	•		the extent to which unfavorable conditions in the general economy, the energy markets or equity markets affect our ability to obtain capital for our planned development projects and future acquisitions on acceptable terms while preserving our credit quality;

	•		restrictions imposed upon us under certain term loans of the Parent;

	•		the extent and timing of generating, pipeline and storage capacity expansion and retirements by others;

	•		changes in or application of federal, state and other regulations to which we, our subsidiaries and/or the projects in which we invest are subject;

	•		changes in or application of environmental and other laws and regulations to which we and our subsidiaries and the projects in which we invest are subject;

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

	•		political, legal and economic conditions and developments in North America where we and our subsidiaries and the projects in which we invest operate;

	•		financial market conditions and changes in interest rates;

	•		weather and other natural phenomena; and

	•		our performance of projects undertaken and the success of our efforts to invest in and develop new opportunities.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, events, levels of activity, performance or achievements.

We use words like “anticipate,” “estimate,” “intend,” “project,” “plan,” “expect,” “will,” “believe,” “could” and similar expressions to help identify forward-looking statements in this Quarterly Report on Form 10-Q/A.

This Quarterly Report on Form 10-Q/A should be read in conjunction with the Company’s Registration Statement on Form S-4, filed with the Securities and Exchange Commission on July 27, 2001 and amended on August 21, 2001.

Overview

PG&E National Energy Group, Inc. (the “Company” or “NEG”) is an integrated energy company with a strategic focus on power generation, greenfield development, natural gas transmission and wholesale energy marketing and trading in North America. We have integrated our generation, development and energy marketing and trading activities to increase the returns from our operations, identify and capitalize on opportunities to increase our generating and pipeline capacity, create energy products in response to dynamic markets and manage risks. We intend to expand our generating and natural gas pipeline capacity and enhance our growth and financial returns through our energy marketing and trading capabilities.

We account for our business in two reportable segments, integrated energy and marketing (or “Energy”) and interstate pipeline operations (or “Pipeline”). Energy is comprised of PG&E Generating Company, LLC and its subsidiaries and PG&E Energy Trading Holdings Corporation, which owns PG&E Energy Trading-Power, L.P. and PG&E Energy Trading-Gas Corporation and other affiliates. Pipeline is comprised of PG&E Gas Transmission Corporation and its subsidiaries (collectively “GTC”), which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively “GTN”). Other subsidiaries of GTC, PG&E Gas Transmission, Texas Corporation and its subsidiaries and PG&E Gas Transmission Teco, Inc and its subsidiaries (collectively “GTT”) were sold in December 2000. GTT, when acquired in 1997, included pipeline operations, natural gas processing operations and energy trading activities. GTT’s energy trading activities were reorganized and transferred in two stages to our energy segment in 1998 and 1999. Our sale of GTT, included the energy trading activities originally acquired in 1997. The activities in Energy that were disposed of as part of the GTT sales provided approximately $305 million and $809 million in revenues for the three and nine months ended September 30, 2000, respectively. Net income contributed by these activities was $2 million and $10 million in the three and nine months ended September 30, 2000, respectively.

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

The following table sets forth the operating revenues and net income attributable to each of our operating segments as well as cash provided by or used in operations, investing and financing activities (in millions):


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

			2001			2000				2001			2000

Operating revenues
	Energy		$	3,312		$	4,814			$	10,138		$	10,937
	Pipeline:
		GTC		57			62				186			175
		GTT		—			260				—			709
	Eliminations and other			(8	)		2				(4	)		3

Total operating revenues			$	3,361		$	5,138			$	10,320		$	11,824

Operating expenses
	Energy		$	3,205		$	4,772			$	9,897		$	10,805
	Pipeline:
		GTC		28			26				80			76
		GTT		—			246				—			656
	Eliminations and other			(8	)		1				(3	)		2

Total operating expenses			$	3,225		$	5,045			$	9,974		$	11,539

Net income
	Energy		$	64		$	25			$	152		$	81
	Pipeline:
		GTC		19			16				57			43
		GTT		—			—				—			—
	Eliminations and other			(6	)		(17	)			(7	)		(16	)

Total net income			$	77		$	24			$	202		$	108

Net cash provided by operating activities			$	282		$	(2	)		$	316		$	59
Net cash used in investing activities				(490	)		(288	)			(1,165	)		(1,115	)
Net cash provided by financing activities				133			228				837			1,057

Results of Operations

Three Months Ended September 30, 2001 as Compared to Three Months Ended September 30, 2000

Operating Revenues.Our operating revenues were $3.4 billion in the three months ended September 30, 2001, a decrease of $1.8 billion or 35% from the three months ended September 30, 2000. This decline in operating revenues occurred principally in our wholesale energy trading business with a decrease of $1.5 billion primarily due to a decline in volumes and realized prices in the third quarter of 2001 as compared to the same period last year. In our pipeline segment, the decline in operating revenues of approximately $300 million is primarily due to the sale of GTT in December 2000.

Operating Expenses.Our operating expenses were $3.2 billion in the three months ended September 30, 2001, a decrease of $1.8 billion or 36% from the three months ended September 30, 2000. This decline in operating expenses occurred principally in our wholesale energy trading business with a decrease of $1.6 billion due to a decline in volumes and realized prices in the third quarter of 2001 as compared to the same period last year. In our

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

pipeline segment, the decline in operating expenses of $244 million is primarily due to the sale of GTT in December 2000.

Net Income.Our net income (after discontinued operations) was $77 million for the three months ended September 30, 2001, an increase of $53 million from the three months ended September 30, 2000. The quarter ended September 30, 2000 included a loss from discontinued operations of $19 million related to losses on the disposal of PG&E Energy Services. Income from continuing operations increased $34 million for the quarter ended September 30, 2001 as compared to the same period last year. Our pre-tax operating income increased $43 million mainly due to the sale of a development project in the third quarter of 2001 which provided pre-tax income of $23 million and higher gross margins at our wholesale energy trading business. Net interest expense was $12 million higher in the third quarter of 2001 as compared to the same period last year, principally due to the higher cost of borrowing. Finally, the company had a lower effective tax rate for the third quarter of 2001 as compared to the same period last year mainly due to IRS Section 29 tax credits.

Nine Months Ended September 30, 2001 as Compared to Nine Months Ended September 30, 2000

Operating Revenues.Our operating revenues were $10.3 billion in the nine months ended September 30, 2001, a decrease of $1.5 billion, or 13% from the nine months ended September 30, 2000. This decline in operating revenues occurred principally in our wholesale energy trading business mainly due to a decline in volumes and realized prices, primarily in the third quarter of 2001, as compared to the prior year. In our pipeline segment, the decline in operating revenues of approximately $700 million is primarily due to the sale of GTT in December 2000.

Operating Expenses.Our operating expenses were $10 billion in the nine months ended September 30, 2001, a decrease of $1.6 billion or 14% from the nine months ended September 30, 2000. This decline in operating expenses occurred principally in our wholesale energy trading business mainly due to a decline in volumes and realized prices, primarily in the third quarter of 2001, as compared to the prior year. In our pipeline segment, the decline in operating expenses of $652 million is primarily due to the sale of GTT in December 2000.

Net Income.Our net income (after discontinued operations) was $202 million for the nine months ended September 30, 2001, an increase of $94 million from the nine months ended September 30, 2000. The nine months ended September 30, 2000 included a loss from discontinued operations of $19 million related to losses on the disposal of PG&E Energy Services. Income from continuing operations increased $75 million for the nine months ended September 30, 2001 as compared to the same period last year. Our pre-tax operating income increased $61 million mainly due to the sale of a development project in the third quarter of 2001 which provided pre-tax income of $23 million and higher gross margins at our wholesale energy trading business. Net interest expense was $23 million lower in the nine months ended September 30, 2001 as compared to the same period last year, principally due to higher interest income and increased capitalization of interest. Finally, the company had a lower effective tax rate for the nine months ended September 30, 2001 as compared to the prior years mainly due to IRS Section 29 tax credits.

Liquidity and Capital Resources

Capital expenditures in our generation operations and natural gas transmission business, debt service requirements and working capital needs associated with our energy trading and marketing operations have been the primary demands on our cash resources. In addition, we often must provide guarantees, letters of credit and collateral for our contractual commitments.

Sources of Liquidity

Historically, we have obtained cash from recourse and non-recourse financings, from capital contributions and loans by the Parent, and from distributions and fees from our subsidiaries and project affiliates. In many cases, the loan, partnership and other agreements that apply to our subsidiaries and project affiliates restrict these entities from

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

distributing cash to us unless, among other things, debt service, lease obligations, and any applicable preferred payments are current, the applicable subsidiary or project affiliate meets certain debt service coverage ratios, a majority of the participants approve the distribution, and there are no events of default. In addition, the subsidiaries that own our natural gas transmission facilities and our energy trading businesses have been “ringfenced” and cannot pay dividends to us unless the subsidiary’s board of directors or board of control, including its independent director, unanimously approves the dividend payment.

Historically, we have borrowed funds from and loaned funds to the Parent for specific transactions or other corporate purposes. These intercompany loans accrued interest at the Parent’s short-term borrowing rates through December 31, 2000, and accrued interest at a floating LIBOR based rate from January 1, 2001. As of September 30, 2001, we had a net outstanding loan balance payable to the Parent of $122 million, of which $118 million is recorded as Long-term advances from Parent on the consolidated balance sheet. The Parent also has contributed equity capital to finance a portion of the acquisition and construction costs of various capital projects and for other corporate purposes. We have, in turn, paid dividends to the Parent.

In addition, Attala Power Corporation (“APC”), an indirect wholly-owned subsidiary of the Company, has a non-recourse demand note payable to the Parent of $309 million, which is classified as short-term on the consolidated balance sheet as of September 30, 2001. The demand note between APC and the Parent is recourse only to the assets of APC and not to the Company.

The Parent historically provided us credit support for a range of our contractual commitments. With respect to our generating facilities, this credit support included agreements to infuse equity in specific projects when these projects began operations or when we purchased a project that we had leased. The Parent also provided guarantees of our obligations under several long-term tolling arrangements and for our commitments under various energy trading contracts entered into by our energy trading operations. The Parent also provided guarantees to support several letter of credit facilities issued by our energy trading operations to provide short-term collateral to counterparties. As of September 30, 2001, except for $8 million of guarantees relating to various energy trading master contracts (with no related exposure to PG&E Corporation), we replaced all Parent equity infusion agreements and guarantees with our own equity infusion agreements, guarantees or other forms of security.

We do not intend to lend or borrow from the Parent in the future nor do we expect to receive any future capital contributions (either directly or to our subsidiaries) or guarantees from the Parent. We may not pay dividends to the Parent unless our board of directors, including our independent director, unanimously approves the dividend payment and unless we have either a rating of Baa3 from Moody’s or BBB- from Standard & Poor’s or meet a 2.25 to 1.00 consolidated interest coverage ratio.

In connection with the replacement of the Parent guarantees with our own, and with the continued growth of our energy trading and marketing positions, we have experienced a substantial increase in the need for various liquidity facilities to provide letters of credit and cash deposits with various counterparties. Our cash margin deposits outstanding to counterparties net of cash margin received from counterparties increased from $10 million as of December 31, 2000 to $18.8 million as of September 30, 2001. On June 15, 2001, we established a $550 million revolving credit facility, which includes the ability to issue letters of credit with a syndicate of banks to support our energy trading operations and for other working capital requirements. The $550 million revolving credit facility was subsequently increased to $1.25 billion on August 23, 2001. On September 30, 2001, $156 million of letters of credit were outstanding under this facility and borrowings of $295 million were outstanding under this facility.

In addition, we maintain various revolving credit facilities at subsidiary levels, which currently are available to fund our capital and liquidity needs.. A $500 million 364-day facility and a $550 million five-year facility were repaid and cancelled on August 23, 2001. Our generation operation maintains one $100 million revolving credit facility, which expires in September 2003. GTN maintains a $100 million revolving credit facility that expires in May 2002 (but may be extended for successive one-year periods). Outstanding loans on these two facilities are charged LIBOR-based interest rates with an interest rate spread over LIBOR tied to the credit rating of the

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

applicable subsidiary and the amount drawn on the facility. The revolving credit facilities can be used to back commercial paper As of September 30, 2001, we had borrowed $99 million against our total $200 million borrowing capacity under these facilities. In addition, approximately $31 million of letters of credit were outstanding under these facilities.

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

We have made substantial commitments and have numerous options to increase our owned and controlled generating and pipeline capacity. In order to finance planned growth in our owned and controlled generating and pipeline capacity and our energy marketing and trading operations, we intend to implement a financing strategy with the following key elements:

	•		maintain our existing investment grade rating—investment grade ratings are particularly important to efficiently meet the credit and collateral requirements associated with our trading activities;

	•		maintain our short-term debt facilities so that we generally have sufficient liquidity to meet short-term cash needs and to efficiently provide letters of credit to replace cash margin deposits;

	•		continue to use longer-term capital market debt to refinance shorter-term debt;

	•		increase our use of loans and financings secured by multiple generating facilities;

	•		pursue the sale of some of our owned generating facilities to strategic and financial investors;

	•		enter into leases and/or tolling agreements that will allow us to continue to control the output of these facilities; and

	•		issue preferred or common equity.

Under the terms of the Parent’s credit facility, our issuance of equity, other than through an initial public offering, would be a default unless the lenders consented. In addition, following an initial public offering, the Parent would be required to reduce the amount of its term loans to an aggregate of $500 million. Neither we nor the Parent require approval of lenders to transfer to third parties all or a portion of the equity of a number of lower level subsidiaries, including those holding our advanced development projects, so long as we retain the proceeds as cash, use the proceeds to pay down debt or reinvest the proceeds in our business. Options we are currently evaluating for raising additional equity include an initial public offering, a private placement of our common and/or preferred equity, the sale of a minority interest in a subsidiary holding our integrated energy and marketing business segment, and the issuance of equity in an entity that would be formed to hold a selected group of generating projects, primarily including projects currently in advanced development.

Under various guarantees that we have provided, including the guarantees issued to support Lake Road, La Paloma, Harquahala, as well as our subsidiary’s $280 million equipment purchase revolving credit facility, if our credit rating were downgraded below investment grade, we would be required to provide alternative credit enhancements such as guarantees of our investment grade subsidiaries, letters of credit or cash collateral. If we were unable to provide such enhancements within 30 days, the guaranteed loans would be due and payable within five days. If such loans were not repaid within this period, the lenders to those projects would have the right to stop lending under the applicable financing agreements, we would be required to repay all the loans and the lenders could foreclose on the project assets and call on our guarantees. If we were unable to perform under the guarantees, we could be in default under all of our senior obligations, including the Senior Notes, which could materially harm our

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

business. In addition, we or various of our subsidiaries have guaranteed the financial performance of our trading subsidiaries to various trading counterparties. If we fail to maintain an investment grade rating, alternative security would have to be posted in the form of other investment grade guarantees, letters of credit or cash collateral. If we are unable to provide these enhancements, certain valuable contractual assets could be lost and certain trading obligations could be accelerated which could materially harm our business.

Commitments and Capital Expenditures

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

Generating Projects in Construction

We currently own, control, or will own the output of ten generating facilities under construction: Lake Road, La Paloma, Athens, Plains End, Harquahala, Covert, Southaven, Caledonia, Otay Mesa and Liberty Electric.

We had entered into agreements with a trust that would have owned and financed turbine payments and project related costs for the Harquahala facility. In the third quarter, We decided not to pursue a post construction operating lease facility. Consequently, we began to directly fund the construction of this project with its own resources and began to consolidate the special purpose entity. The construction costs of $120 million are classified as Construction work in progress and the borrowings in the amount of $120 million are classified as Long-term debt.

We are in the process of arranging a $1.75 billion multi-project financing facility that would provide construction financing for Harquahala, Athens and Covert. If this facility were implemented, we would use proceeds from facility loans to purchase the Harquahala project from the trust. In addition, the completed Millennium facility would be contributed as equity to this pool of assets. We would provide additional equity contributions or commitments as required. We also have agreed to pay capital costs in excess of a predetermined amount required to complete construction of Covert and Harquahala. As of September 30, 2001, we have paid approximately $422 million. Loan repayment would be secured by all of the projects in the pool and, other than our equity commitment agreements, would be non-recourse to us. We expect to implement this facility before the end of 2001.

In connection with the Southaven project financing and our tolling agreement, we have provided to the owner of that project, a subsidiary of Cogentrix, a commitment to provide a subordinated loan of up to $75 million at the time of completion of the project, if at that time we are not rated at least Baa2 by Moody’s and BBB by Standard & Poor’s, with at least a stable outlook.

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

On September 6, 2001, a subsidiary of the Company entered into a Credit agreement for $69.4 million. The debt facility will be used to fund construction of the Plains End project. This facility expires upon the earlier of five years after commercial operations has been declared or September 30, 2007. The facility provides for borrowings that bear interest based on LIBOR plus a credit spread. On September 19, 2001 and September 27, 2001, the subsidiary executed accreting and amortizing interest rate swaps to hedge approximately 80% of loans expected to be drawn.

Turbine Purchase Commitments

We have entered into commitments to ensure that we have the turbines and other equipment necessary to meet our growth plans. Most significantly, we have secured contractual commitments and options for 60 new advanced technology combustion turbines representing 20,218 MW of net generating capacity. Sixteen of these turbines, representing approximately 5,019 MW, are for generating facilities under construction or recently placed in operation as of September 30, 2001. Subject to maintaining our credit quality and raising necessary capital, we expect to continue to develop projects that deploy some or all of these turbines.

In 2000, we entered into agreements to own and facilitate the development and construction financing of generating facilities that will use 44 turbines to be manufactured by General Electric and Mitsubishi. The Parent and we committed to provide up to $314 million in equity to meet our obligations. As of May 31, 2001, we had incurred $216 million of expenditures. We used $216 million of our new $280 million revolving credit facility to purchase the turbines. As of September 30, 2001, the amount that has been drawn under this facility is $276 million. We also provided guarantees to equipment vendors in an aggregate amount in excess of $150 million. Our equity commitments have been terminated.

We have entered into, or agreed to enter into, long-term service agreements with the turbine manufacturers for the maintenance and repair of the 60 turbines for which we have secured contractual commitments and options. These agreements also cover maintenance and repair of the generating facilities in which the turbines will be used. We expect our commitments under these long-term service agreements will expire at various times through 2021 and will total approximately $3.5 billion. Actual payments under these agreements will vary depending on the output generated by the facilities and other operating factors.

Long-term Tolling Commitments

We also have entered into a number of long-term tolling agreements. As of September 30, 2001, our annual estimated committed payments under these contracts ranged from $0.8 million to $320.2 million, resulting in total committed payments over the next 27 years of approximately $6.3 billion. We provide guarantees under each of these agreements and receive guarantees from our counterparties. As of September 30, 2001, we have provided or committed to provide guarantees to support these tolling agreements totaling up to $1.1 billion.

Generating Projects in Development

We have reviewed our growth plans for our electric generating business in light of circumstances presented by recent changes in energy and equity markets as well as the slowdown of the U.S. economy. Further, energy prices and price-earnings multiples for competitive energy companies have significantly declined, thereby constraining access to equity funds at acceptable terms to the NEG. In response to these market changes, we continue to assess and modify our growth plans for ownership and control of electric generating facilities to manage our future capital and equity requirements. As a result, based on our view of the regional energy markets, we expect to delay, swap or sell generation development projects that are currently not under construction and associated commitments to take delivery of turbines. Management expects our total of owned and controlled generating capacity will be less than the 22,000 megawatts in 2004 that had been previously forecast. Since our review is ongoing, it is not practical to provide new projections of the total capacity that we will own or control in 2004.

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

Other Commitments and Plans

Our energy marketing and trading operations have a number of outstanding commitments under various energy trading contracts, for which we or the Parent have provided guarantees. As of September 30, 2001, the face value of these guarantees totaled $4.4 billion. Of this amount, the Parent provided $8 million, for which there is no exposure to the Parent. We are finalizing discussions with the remaining counterparty to replace the remaining Parent guarantees with our own.

We also have other long-term contractual commitments associated with our existing generation and trading business, including power purchase agreements, gas supply and transportation agreements, operating lease agreements and agreements for payments in lieu of property taxes.

We plan to expand the capacity of our GTN pipeline by approximately 370,000 decatherms per day by the end of 2003. The first phase of this expansion, approximately 220,000 decatherms per day, is to be completed by the end of 2002 and to cost approximately $122,000. As a result of contracts recently finalized, we intend to complete a second phase of this expansion of approximately 150 million decatherms per day of additional capacity at a cost of approximately $111 million, to be completed by the end of 2003. We expect to fund these expansions from the issuance of additional debt, available cash or draws on available lines of credit. The Company has also initiated development of a Washington lateral pipeline that would originate at the GTN mainline system near Spokane, Washington and extend approximately 260 miles to western Washington.

In addition, we have entered into a joint venture for the development of a new 500 million cubic feet per day gas pipeline, North Baja, to deliver natural gas to Northern Mexico and Southern California. The North Baja project is expected to be completed by the end of 2002. We own all of the United States section of this cross-border project. Our share of the costs to develop this project will be approximately $146 million. We expect to fund this project from the issuance of non-recourse debt, and available cash or draws on available lines of credit.

We purchased Attala, a partially constructed power plant, in September 2000 for $311 million. Under the purchase agreement, we also prepaid the remaining construction costs to the seller, who was obligated to complete construction and deliver a fully operational facility to us by July 1, 2001. Attala commenced commercial operation in June 2001. We funded the initial purchase price in part with a $309 million non-recourse, secured short-term loan from the Parent. We intend to sell the project and lease it back. We expect to use the proceeds of the sale to retire the loan from the Parent or to otherwise refinance the project and satisfy the Parent loan by the end of 2001.

We have agreed to supply the full service power requirements of the City of Denton, Texas, for a period of five years beginning July 1, 2001. The City of Denton’s peak load forecast is 272 MW in 2001 increasing to 314 MW over the term of the contract. Our supply obligation to the city is net of about 97 MW of generation entitlements still retained by the city (plus 40 MW of purchased power that the city has assigned to us for summer 2001). In connection with the power supply agreement, we acquired the 178 MW gas-fired Spencer station from the city and have also agreed to acquire two small hydroelectric facilities from the city. The total consideration of approximately $12 million was recorded in June 2001.

On September 17 and 28, 2001, the Company purchased Mountain View Power Partners, LLC and Mountain View Power Partners II, LLC, respectively. These companies own 44.4 and 22.2 megawatt wind energy projects, respectively, near Palm Springs, California. The Company has contracted with SeaWest WindPower, Inc. for the operation and maintenance of the wind units and will sell the entire output of the two wind projects, under a long-term contract. Total consideration for these two companies was $92 million.

Operating Activities

During the nine months ended September 30, 2001, we provided net cash of $316 million in operating activities. Net cash from operating activities before changes in other working capital accounts was $114 million driven

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

primarily by our increased net income. Our net cash inflow related to certain other working capital accounts was $202 million, driven primarily by deliveries of much of our previously held forward positions in trading.

Investing Activities

During the nine months ended September 30, 2001, we used net cash of $1,165 million in investing activities. Our cash outflows from investing activities were primarily attributable to capital expenditures on generating projects in construction and advanced development and turbine prepayments.

Financing Activities

During the nine months ended September 30, 2001, we provided net cash of $837 million in financing activities principally from the net proceeds related to the Senior Notes.

Environmental Matters

In May 2000, the Company 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 the Company to provide certain information, relative to the compliance of the Company’s Brayton Point and Salem Harbor Generating Stations with the CAA. No enforcement action has been brought by the EPA to date. The Company has had very preliminary discussions with the EPA to explore a potential settlement of this matter. As a result of this and related regulatory initiatives by the Commonwealth of Massachusetts, the Company is exploring initiatives that would assist the Company to achieve significant reductions of sulfur dioxide and nitrogen oxide emissions by as early as 2006 to 2010. Management believes that the Company would meet these requirements through installation of controls at the Brayton Point and Salem Harbor plants and estimates that capital expenditures on these environmental projects will be approximately $265 million through 2006. 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.

GenLLC’s existing power plants, including USGen New England, Inc. (“USGenNE”) facilities, are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. Three of the fossil-fueled plants owned and operated by USGenNE are operating pursuant to NPDES permits that have expired. For the facilities whose NPDES permits have expired, permit renewal applications are pending, and it is anticipated that all three facilities will be able to continue to operate under existing terms and conditions until new permits are issued. It is estimated that USGenNE’s cost to comply with the new permit conditions could be as much as $60 million through 2005. It is possible that the new permits may contain more stringent limitations than prior permits.

We anticipate spending up to approximately $330 million, net of insurance proceeds, through 2008 for environmental compliance at currently operating facilities. We believe that a substantial portion of this amount will be funded from our operating cash flow. This amount may change, however, and the timing of any necessary capital expenditures could be accelerated in the event of a change in environmental regulations or the commencement of any enforcement proceeding against us.

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

Price Risk Management Activities

We have established a risk management policy that allows derivatives to be used for both trading and non-trading purposes (a derivative is a contract whose value is dependent on or derived from the value of some underlying asset). We use derivatives for hedging purposes primarily to offset our primary market risk exposures, which include commodity price risk, interest rate risk and foreign currency risk. We also participate in markets using derivatives to gather and use market intelligence, create liquidity and maintain a market presence. Such derivatives include forward contracts, futures, swaps, options and other contracts.

We may only engage in the trading of derivatives in accordance with policies and procedures established by our risk management committee, as well as with policies set forth by the corporate risk policy committee of the Parent. Trading is permitted only after our risk management committee authorizes such activity subject to appropriate financial exposure limits. Both committees are comprised of senior executive officers.

At September 30, 2001, our risk management assets and liabilities declined approximately $3.8 billion each from year-end 2000, with our net position only changing by $80 million. These declines in our assets and liabilities were commensurate with seasonality fluctuations where positions held were delivered before the end of the third quarter 2001, as well as, some reduced trading volume levels compared to year-end 2000.

Commodity Price Risk

Commodity price risk is the risk that changes in market prices will cause earnings, value and cash flows to vary from expectations. We are primarily exposed to the commodity price risk associated with energy commodities such as electric power and natural gas. Therefore, our price risk management activities primarily involve buying and selling fixed-price commodity commitments into the future. Net open positions often exist or are established due to our assessment of and response to changing market conditions. To the extent that we have an open position, we are exposed to the risk that fluctuating market prices may adversely impact our financial results.

We prepare a daily assessment of our commodity price risk exposure using value-at-risk and other methodologies that simulate future price movements in the energy markets to estimate the size and probability of future potential losses. We quantify market risk 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 the selection of a confidence level for losses and a portfolio holding period. In addition, assumptions are made regarding volatility of prices, price correlations across products and markets and market liquidity.

We utilize historical data for calculating the price volatility of our positions and how likely the prices of those positions will move together. The model includes all derivative and commodity investments in our trading portfolio and only derivative commodity investments for our non-trading portfolio (but not the related underlying hedged position). We express value-at-risk as a dollar amount of the potential reduction in the fair value of our portfolio from changes in prices over a one-day holding period based on a 95% one-tailed confidence level. Therefore, there is a 5% probability that our portfolio will incur a loss in one day greater than our value-at-risk. For example, if value-at-risk is calculated at $5 million, we can state with a 95% confidence level that if prices moved against our positions, the reduction in the value of our portfolio resulting from such one-day price movements would not exceed $5 million. Based on value-at-risk analysis of the overall commodity price risk exposure of the trading business on September 30, 2001, we did not anticipate a materially adverse effect on our Consolidated Financial Statements as a result of market fluctuations.

The Company’s daily value-at-risk commodity price risk exposure as of September 30, 2001, was $8 million for trading activities and $19 million for non-trading activities.

This methodology 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

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

a portfolio to extreme price movements and the inability to address the risk resulting from intra-day trading activities.

Interest Rate Risk

Floating rate exposure measures the sensitivity of corporate earnings and cash flows to changes in short-term interest rates. This exposure arises when short-term debt is rolled over at maturity, when interest rates on floating rate notes are periodically reset according to a formula or index, and when floating rate assets are financed with fixed rate liabilities. We manage our exposure to short-term interest rates by using an appropriate mix of short-term debt, long-term floating rate debt, and long-term fixed rate debt.

Financing exposure measures the effect of an increase in interest rates that may occur related to any planned or expected fixed rate debt financing. This includes the exposure associated with replacing debt at maturity. We will hedge financing exposure in situations where the potential impairment of earnings, cash flows, and investment returns or execution efficiency, or external factors (such as bank imposed credit agreements) necessitate hedging.

We evaluate the short-term and long-term interest rate exposure and consider our overall corporate finance objectives when considering proposed hedges. We evaluate the use of the following interest rate instruments to manage our interest rate exposure: interest rate swaps, interest rate caps, floors, or collars, swaptions, or interest rate forwards and futures contracts.

Interest rate risk sensitivity analysis is used to measure our interest rate price risk by computing estimated changes in cash flows as a result of assumed changes in market interest rate. As of September 30, 2001, if interest rates had averaged 1% higher, estimated losses would not have had a material impact on NEG’s financial statements.

Foreign Currency Risk

The Company is exposed to foreign currency risk associated with the Canadian dollar. The Company uses sensitivity analysis to measure its foreign currency exchange rate exposure to the Canadian dollar. As of September 30, 2001, if the Canadian dollar experienced 10% devaluation, estimated losses would not have had a material impact on the Company’s Consolidated Financial Statements.

New Accounting Standards

We adopted Statement of Financial Accounting Standards (“SFAS”) No. 133,Accounting for Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138 as of January 1, 2001. This standard requires us to recognize all derivatives, as defined in SFAS No. 133, on our balance sheet at fair value. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income, a component of equity, until the hedged items are recognized in earnings. The transition adjustment to implement the new standard was an immaterial adjustment to net income and a negative adjustment of approximately $333 million (after tax) to other comprehensive income, a component of stockholder’s equity. This transition adjustment, which relates to hedges of interest rate, foreign currency and commodity price risk exposure, was recognized as of January 1, 2001, as a cumulative effect of a change in accounting principle.

We also have certain 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 thus are not reflected on the balance sheet at fair value. In June 2001 (as revised in October 2001), the Financial Accounting Standards Board (“FASB”) approved an interpretation issued by the Derivatives Implementation Group (“DIG”) that changes the definition of normal

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

purchases and sales for certain power contracts. We must implement this interpretation on January 1, 2002, and are currently assessing the impact of these new rules. The FASB has also approved another DIG interpretation that disallows normal purchases and sales treatment for commodity contracts (other than power contracts) that contain volumetric variability or optionality. Certain of our derivative commodity contracts may no longer be exempt from the requirements of SFAS No. 133. We are evaluating the impact of the implementation guidance on our financial statements and will implement this guidance, as appropriate, by the implementation deadline of April 1, 2002.

In June 2001, the FASB issued SFAS No. In June 2001, the FASB issued SFAS No. 141,Business Combinations. This standard prohibits the use of the pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. We do not expect that implementation of this standard will have a significant impact on our financial statements.

Also in June 2001 the FASB issued SFAS No. 142,Goodwill and Other Intangible Assets. This standard eliminates the amortization of goodwill, and requires goodwill to be reviewed periodically for impairment. This standard also requires the useful lives of previously recognized intangible assets to be reassessed and the remaining amortization periods to be adjusted accordingly. This standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on our statement of financial position at that date, regardless of when the assets were initially recognized. We are assessing the impact of this standard on our financial statements.

In July 2001, the FASB issued SFAS No. 143,Accounting for Asset Retirement Obligations. This standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets. We have not yet determined the effects of this standard on our financial statements.

In October 2001, the FASB issued SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets.SFAS No. 144 supercedes SFAS No. 121,Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,but retains its fundamental provisions 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 are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should cease to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, superceding previous guidance for discontinued operations of business segments. This Statement is effective for fiscal years beginning after December 15, 2001. We are assessing the impact of this standard on our financial statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

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

PART II. OTHER INFORMATION
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits:

Exhibit 10— For exhibits see Company's Registration Statement on Form S-4, filed with the Securities and Exchange Commission on July 27, 2001 and amended on August 21, 2001.

(b) The following Current Reports on Form 8-K were filed during the third quarter of 2001 and through the date hereof:

None.

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, on March 5, 2002.


		PG&E NATIONAL ENERGY GROUP, INC. (Registrant)

		By: /s/ Thomas G. Boren Thomas G. Boren President and Chief Executive Officer

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

Pg&e National Energy Inactive 10-Q/A2001 Q3 Quarterly report (amended)