NRG NORTHEAST GENERATING LLC - 10-Q Quarterly Report

None (Former name, former address and former fiscal year, if changed since last report)

Indicate by check mark whether the Registrant (1) has filed all reports to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities and Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.


		Page No.

Part I
Item 1 Consolidated Financial Statements and Notes
	Consolidated Statements of Operations		3
	Consolidated Balance Sheets		4
	Consolidated Statements of Members’ Equity		5
	Consolidated Statements of Cash Flows		6
	Notes to Consolidated Financial Statements		7
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations			31
Item 3 Quantitative and Qualitative Disclosures About Market Risk			31
Item 4 Controls and Procedures			31
Part II
Item 1 Legal Proceedings			32
Item 3 Defaults on Senior Securities			32
Item 6 Exhibits, Financial Statement Schedules, and Reports on Form 8-K			32
	Cautionary Statement Regarding Forward Looking Information		32
SIGNATURES			35

NRG Northeast Generating LLC and Subsidiaries
Consolidated Statements of Operations
(UNAUDITED)


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

(In thousands)		2003			2002 (Restated)			2003			2002 (Restated)

Operating revenues
	Revenues	$	260,472		$	233,604		$	603,858		$	550,252
Operating costs and expenses
	Operating costs		145,400			182,104			500,601			390,657
	Depreciation		14,295			13,639			51,065			39,790
	General and administrative expenses		12,568			5,330			29,915			16,671
	Restructuring professional fees and expenses		515			—			1,081			—
	Restructuring and impairment charges		9,088			49,289			232,335			49,289

Operating (loss) income			78,606			(16,758	)		(211,139	)		53,845
Other income (expense)
	Other income, net		(27	)		133			(23	)		5,167
	Restructuring interest income		2			—			5			—
	Interest expense		(14,600	)		(12,877	)		(40,302	)		(39,621	)

Net (loss) income		$	63,981		$	(29,502	)	$	(251,459	)	$	19,391

NRG Northeast Generating LLC and Subsidiaries
Consolidated Balance Sheets (UNAUDITED)


					September 30,		December 31,
(In thousands)					2003		2002

Assets
Current Assets:
	Cash and cash equivalents				$	126	$	14,354
	Cash — restricted					3,555		—
	Accounts receivable, net of allowance for doubtful accounts of $0 and $1,344					285		118,153
	Accounts receivable — affiliate					622,893		—
	Inventory					130,175		123,963
	Derivative instruments valuation					253		23,039
	Prepaid expenses					39,489		38,309

		Total current assets				796,776		317,818
Property, plant and equipment, net of accumulated depreciation of $163,139 and $157,534						1,056,068		1,333,928
Deferred finance costs, net of accumulated amortization of $4,281 and $1,161						13,412		8,995
Derivative instruments valuation						—		9,601
Other assets, net of accumulated amortization of $4,359 and $2,605						28,996		23,395

		Total assets			$	1,895,252	$	1,693,737
Liabilities and Members’ Equity
Liabilities:
	Current portion of long-term debt				$	—	$	556,500
	Note payable — affiliate					—		30,000
	Accounts payable					—		14,607
	Accounts payable — affiliates					—		11,476
	Accrued fuel and purchased power expense					—		37,168
	Accrued interest					14,993		4,198
	Other accrued liabilities					6,341		11,713
	Derivative instruments valuation					646		13,017

		Total current liabilities				21,980		678,679
Derivative instruments valuation						—		7,559
Other long-term obligations						348		27,936

		Total liabilities not subject to compromise				22,328		714,174
Liabilities subject to compromise:
			Notes payable			586,500		—
			Accounts payable — trade			20		—
			Accounts payable — affiliate			522,278		—
			Accrued liabilities			46,586		—
			Other liabilities			18,271		—

				Total liabilities subject to compromise		1,173,655		—

Commitments and contingencies
Members’ equity						699,269		979,563

				Total liabilities and members’ equity	$	1,895,252	$	1,693,737

NRG Northeast Generating LLC and Subsidiaries
Consolidated Statements of Members’ Equity (UNAUDITED)


						Accumulated
	Member					Other		Total
	Contributions/		Accumulated			Comprehensive		Members '
(In thousands)	Distributions		Net Income (Loss)			Income (Loss)		Equity

Balances at June 30, 2002	$	788,315	$	207,421		$	66,772	$	1,062,508

Net loss				(29,502	)				(29,502	)
Deferred unrealized gains on derivatives, net							19,035		19,035

Comprehensive loss									(10,467	)

Balances at September 30, 2002, as restated	$	788,315	$	177,919		$	85,807	$	1,052,041

Balances at June 30, 2003	$	788,315	$	(153,027	)	$	—	$	635,288

Net income				63,981					63,981

Comprehensive income									63,981

Balances at September 30, 2003	$	788,315	$	(89,046	)	$	—	$	699,269


	Member					Accumulated Other			Total
	Contributions/		Accumulated			Comprehensive			Members '
(In thousands)	Distributions		Net Income (Loss)			Income (Loss)			Equity

Balances at December 31, 2001	$	788,315	$	158,528		$	107,741		$	1,054,584

Net income				19,391						19,391
Deferred unrealized loss on derivatives, net							(21,934	)		(21,934	)

Comprehensive loss										(2,543	)

Balances at September 30, 2002, as restated	$	788,315	$	177,919		$	85,807		$	1,052,041

Balances at December 31, 2002	$	788,315	$	162,413		$	28,835		$	979,563

Net loss				(251,459	)					(251,459	)
Deferred unrealized loss on derivatives, net							(28,835	)		(28,835	)

Comprehensive loss										(280,294	)

Balances at September 30, 2003	$	788,315	$	(89,046	)	$	—		$	699,269

NRG Northeast Generating LLC and Subsidiaries
Consolidated Statements of Cash Flows (UNAUDITED)


						Nine Months
			Nine Months			Ended
			Ended			September 30, 2002
(In thousands)			September 30, 2003			(Restated)

Cash flows from operating activities:
	Net (loss)/income		$	(251,459	)	$	19,391
	Adjustments to reconcile net (loss)/income to net cash provided (used) by operating activities
		Depreciation		51,883			37,990
		Unrealized (gain)loss on energy contracts		(16,377	)		8,614
		Amortization of other assets		—			651
		Amortization of deferred financing costs		3,120			310
		Asset and impairments		230,570			49,289
		Allowance for doubtful accounts		1,344			—
		(Gain) loss on disposal of property and equipment		(818	)		1,800
		Changes in assets and liabilities:
		Accounts receivable, net		116,524			(43,388	)
		Inventory		(6,212	)		57,418
		Prepaid expenses		(1,180	)		(15,099	)
		Accounts payable		(14,587	)		(1,410	)
		Accounts receivable/payable — affiliates, net		(112,091	)		(70,752	)
		Accrued interest		12,993			14,382
		Accrued fuel and purchased power expense		(3,841	)		(19,881	)
		Other accrued liabilities		23,960			7,939
		Other assets and liabilities		(33,383	)		(1,708	)

Net cash provided by operating activities				446			45,546

Cash flows from investing activities:
		Capital expenditures		(8,458	)		(21,788	)
		Investment in restricted funds		(3,555	)		(310	)
		Proceeds from disposition of property and equipment		4,876			—

Net cash used by investing activities				(7,137	)		(22,098	)

Cash flows from financing activities:
		Deferred financing costs		(7,537	)		—
		Proceeds from note payable — affiliate		—			30,000
		Principal payments on long-term debt		—			(53,500	)

Net cash used by financing activities				(7,537	)		(23,500	)

Net decrease in cash and cash equivalents				(14,228	)		(52	)
Cash and cash equivalents at beginning of period				14,354			370

Cash and cash equivalents at end of period			$	126		$	318

NRG Northeast Generating LLC and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

NRG Northeast Generating LLC (the Company or NRG Northeast), a wholly-owned indirect subsidiary of NRG Energy, Inc. (NRG Energy), owns electric power generation plants in the northeastern region of the United States. The Company was formed for the purpose of financing, acquiring, owning, operating and maintaining, through its subsidiaries and affiliates; facilities owned by Arthur Kill Power LLC, Astoria Gas Turbine Power LLC, Connecticut Jet Power LLC, Devon Power LLC, Dunkirk Power LLC, Huntley Power LLC, Middletown Power LLC, Montville Power LLC, Norwalk Power LLC, Oswego Power LLC and Somerset Power LLC.

On May 14, 2003 (The Petition Date) NRG Energy and 26 of its affiliates (the Debtors) (including the Company and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court) in re: NRG ENERGY, INC., et al., Case No. 03-13024 (PCB) (such proceedings, the Chapter 11 Cases). See Note 2 for a complete list of debtors. It is possible that additional subsidiaries will file petitions for reorganization under Chapter 11. Since the Petition Date, three additional subsidiaries have filed for reorganization under Chapter 11 of the Bankruptcy Code. International operations and certain other subsidiaries were not included in the filing. NRG Energy expects operations to continue as normal during the restructuring process, while it operates its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. For more information about NRG Energy’s restructuring process, refer to the Form 10-K filed by NRG Energy on March 31, 2003, Form 10-Q’s filed by NRG Energy on May 20, 2003 and August 14, 2003.

The accompanying unaudited consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission (SEC) regulations for interim financial information and with the instructions to Form 10-Q. Accordingly, they do not include all of the information and footnotes required by generally accepted accounting principles for complete financial statements. The accounting policies followed by the Company are set forth in Item 15 — Note 2 to the Company’s financial statements in its annual report on Form 10-K for the year ended December 31, 2002 (Form 10-K). The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. Interim results are not necessarily indicative of results for a full year.

The consolidated financial statements have been prepared on a “going concern” basis in accordance with GAAP. The “going concern” basis of presentation assumes that the Company will continue in operation for the foreseeable future and will be able to realize its assets and discharge its liabilities in the normal course of business. Because of the Chapter 11 Cases and the circumstances leading to the filing thereof, the Company’s ability to continue as a “going concern” is subject to substantial doubt and is dependent upon, among other things, confirmation of a plan of reorganization, the Company’s ability to comply with the terms of, and if necessary renew at its expiration in May 2004, the Debtor in Possession Credit Facility, and the Company’s ability to generate sufficient cash flows from operations, asset sales and financing arrangements to meet its obligations. There can be no assurances that this can be accomplished and if it were not, the Company’s ability to realize the carrying value of its assets and discharge its liabilities would be subject to substantial uncertainty. Therefore, if the “going concern” basis were not used for the financial statements, then significant adjustments could be necessary to the carrying value of assets and liabilities, the revenues and expenses reported, and the balance sheet classifications used.

The consolidated financial statements also have been prepared in accordance with The American Institute of Certified Public Accountants Statement of Position 90-7 (SOP 90-7), “Financial Reporting by Entities in Reorganization under the Bankruptcy Code”. Accordingly, all prepetition liabilities believed to be subject to compromise have been segregated in the Consolidated Balance Sheet and classified as liabilities subject to compromise, at the estimated amount of allowable claims. Liabilities not believed to be subject to compromise are separately classified as current and non-current. Interest expense is reported only, subsequent to the petition date, to the extent that it will be paid or that it is probable that it will be an allowed claim.

During the Chapter 11 Cases, the Debtors may, subject to any necessary Bankruptcy Court and lender approvals, sell assets and settle liabilities for amounts other than those reflected in the financial statements. The administrative and reorganization expenses resulting from Chapter 11 Cases will unfavorably affect the Debtors’ results of operations. Future results of operations may also be adversely affected by other factors related to Chapter 11 Cases.

The Company is in the process of reconciling recorded prepetition liabilities with claims filed by creditors with the Bankruptcy Court. Differences resulting from that reconciliation process will be recorded as adjustments to prepetition liabilities. The Company recently began this process and has not yet determined the reorganization adjustments.

In the opinion of management, the accompanying unaudited interim consolidated financial statements contain all material adjustments necessary to present fairly the consolidated financial position of the Company as of September 30, 2003 and December 31, 2002, the results of its operations and members’ equity for the three and nine months ended September 30, 2003 and 2002, and its cash flows for the nine months ended September 30, 2003 and 2002.

Certain prior year amounts have been reclassified for comparative purposes. As previously disclosed, in the Company’s 10-K filed on April 14, 2003, the Company’s results of operations for the three and nine months ended September 20, 2002 have been restated to reflect the impairment of the Somerset facility. This impairment resulted in a $49.3 million change to the Company’s results for the three and nine months ended September 30, 2002.

During 2002, Xcel Energy contributed $500 million to NRG Energy, and NRG Energy and its subsidiaries sold assets and businesses that provided NRG Energy in excess of $286 million in cash and eliminated approximately $432 million in debt. NRG Energy also cancelled or deferred construction of approximately 3,900 MW of new generation projects. On July 26, 2002, Standard & Poors’ (S&P) downgraded NRG Energy’s senior unsecured bonds to below investment grade, and three days later Moody’s also downgraded NRG Energy’s senior unsecured debt rating to below investment grade. Currently, NRG Energy’s unsecured bonds carry a rating of D at S&P and Ca at Moody’s.

In August 2002, NRG Energy retained financial and legal restructuring advisors to assist its management in the preparation of a comprehensive financial and operational restructuring. In November 2002, NRG Energy and Xcel Energy presented a comprehensive plan of restructuring to an ad hoc committee of its bondholders and a steering committee of its bank lenders (the Ad Hoc Creditors Committees). The restructuring plan served as a basis for continuing negotiations between the Ad Hoc Creditors Committees, NRG Energy and Xcel Energy related to a consensual plan of reorganization for NRG Energy.

On March 26, 2003, Xcel Energy announced that its board of directors had approved a tentative settlement agreement with holders of most of NRG Energy’s long-term notes and the steering committee representing NRG Energy’s bank lenders. The terms of the settlement call for Xcel Energy to make payments to NRG Energy totaling up to $752 million for the benefit of NRG Energy’s creditors in consideration for their waiver of any existing and potential claims against Xcel Energy. Under the settlement, Xcel Energy would make the following payments: (i) $350 million, up to $150 million of which may be in Xcel Energy common stock if Xcel Energy’s public debt fails to maintain a certain rating, on the later of: (a) 90 days after NRG Energy’s plan of reorganization is confirmed by the Bankruptcy Court, and (b) one day after the effective date of NRG Energy’s plan of reorganization; (ii) $50 million in the first quarter of 2004. At Xcel Energy’s option, it may fill this requirement with either cash or Xcel Energy common stock or any combination thereof; and (iii) up to $352 million in April 2004. Since the announcement on March 26, 2003, representatives of NRG Energy, Xcel Energy, the bank lenders and noteholders continued to meet to draft the definitive documentation necessary to fully implement the terms and conditions of the tentative settlement agreement. The final settlement agreement between Xcel Energy and NRG Energy is subject to the Bankruptcy Court approval including certain provisions and conditions in its order approving the confirmation of NRG Energy’s plan of reorganization and the satisfaction, or waiver by Xcel Energy, of certain other conditions (including obtaining requisite releases of Xcel Energy by NRG Energy creditors). There can be no assurance that such conditions will be met.

As noted above, on May 14, 2003, the Debtors filed the Chapter 11 Cases. NRG Energy expects operations to continue as normal during the restructuring process, while it operates its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In connection with its Chapter 11 filing, NRG Energy also announced that it had secured a $250 million debtor-in-possession (DIP) financing facility from GE Capital Corporation, subject to Bankruptcy Court approval, to be utilized by its NRG Northeast Generating LLC subsidiary ( NRG Northeast) and some NRG Northeast subsidiaries. The Bankruptcy Court entered an order approving the DIP facility on July 24, 2003. NRG Energy anticipates that the DIP, together with its cash reserves and its ongoing revenue stream, will be sufficient to fund its operations, including payment of employee wages and benefits, during the negotiation process.

Subsequent to the Petition Date, additional NRG Energy subsidiaries filed petitions for reorganization with the Bankruptcy Court. On June 5, 2003, NRG Nelson Turbines LLC and LSP-Nelson Energy LLC (both wholly owned subsidiaries of NRG Energy) filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On August 19, 2003, NRG

McClain LLC (a wholly owned subsidiary of NRG Energy) filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

On May 15, 2003, NRG Energy announced that it had been notified that the New York Stock Exchange (NYSE) has suspended trading in NRG Energy’s corporate units that trade under the ticker symbol NRZ (Units) and that an application to the Securities and Exchange Commission to delist the Units is pending the completion of applicable procedures, including appeal by NRG Energy of the NYSE staff’s decision. NRG Energy does not plan to make such an appeal. The NYSE took this action following NRG Energy’s announcement that it and certain of its affiliates had filed voluntary positions for reorganization under Chapter 11 of the U.S. Bankruptcy Code.

In addition, on May 15, 2003, NRG Energy, NRG Power Marketing, Inc. (NRG PMI), NRG Finance Company I LLC, NRGenerating Holdings (No. 23) B.V. and NRG Capital LLC (collectively, the Plan Debtors) filed their Disclosure Statement for Reorganizing Debtors’ Joint Plan of Reorganization Pursuant to Chapter 11 of the United States Bankruptcy Code (as subsequently amended, the Disclosure Statement). The Bankruptcy Court held a hearing on the Disclosure Statement on June 30, 2003, and instructed the Plan Debtors to include certain additional disclosure. The Plan Debtors amended the Disclosure Statement and obtained Bankruptcy Court approval for the Third Amended Disclosure Statement for Debtors’ Second Amended Joint Plan of Reorganization Pursuant to Chapter 11 of the Bankruptcy Code (respectively, the Amended Disclosure Statement, the Plan) on October 14, 2003.

The Plan must be approved by the SEC prior to its becoming effective. As subsidiaries of a registered holding company (Xcel Energy) under the Public Utility Holding Company Act of 1935 (PUHCA), any reorganization plan for NRG Energy or NRG Energy’s subsidiaries must be approved by the SEC prior to such plan becoming effective. Furthermore, each solicitation of any consent in respect of any reorganization plan must be accompanied or preceded by a copy of a report on the plan made by the SEC, or an abstract thereof made or approved by the SEC. The Plan and Amended Disclosure Statement were submitted to the SEC for review on July 28, 2003. The SEC issued an order approving the Plan on October 10, 2003, permitting the Plan Debtors, subject to the approval of the Bankruptcy Court, to commence solicitation of votes on the Plan.

The Plan Debtors commenced solicitation of votes on the Plan on October 14, 2003. The voting deadline by which holders of claims and equity interests of the Plan Debtors must submit their ballots accepting or rejecting the Plan was November 12, 2003. Objections to confirmation of the Plan must be filed with Bankruptcy Court by November 12, 2003. The Bankruptcy Court has scheduled the confirmation hearing to determine whether the Plan should be confirmed on November 21, 2003.

If the Plan is confirmed, holders of NRG Energy unsecured claims (including bank and bond debt) will receive a combination of New NRG Energy common stock, New NRG Energy senior notes and cash for an estimated percentage recovery of 50.7%. Holders of NRG PMI unsecured claims will receive a combination of New NRG Energy common stock and New NRG Energy senior notes for an estimated percentage recovery of 44.6%. If the Plan is confirmed, certain other holders of claims or equity interests in the Plan Debtors will (i) have their claims paid in full in accordance with the Bankruptcy Code, (ii) have their claims or equity interests reinstated, or (iii) have their claims or equity interests cancelled, and receive no distribution on account of such claims or equity interests. Upon emergence from bankruptcy, Xcel Energy’s ownership interest in NRG Energy will be cancelled and ownership in NRG Energy will vest in the unsecured creditors of NRG Energy and NRG PMI.

On September 17, 2003, NRG Northeast and NRG South Central Generating LLC (NRG South Central) and certain of their subsidiaries and affiliates filed a plan of reorganization with the Bankruptcy Court (the NRG Northeast and NRG South Central Plan). The debtors under the NRG Northeast and NRG South Central Plan are not soliciting votes for approval of the NRG Northeast and NRG South Central Plan because none of the holders of claims or equity interests are impaired under the NRG Northeast and NRG South Central Plan. The Bankruptcy Court has scheduled a hearing on the confirmation of the NRG Northeast and NRG South Central Plan on November 21, 24 and 25, 2003.

As stated above, NRG Energy and certain of its subsidiaries (including NRG Northeast and its subsidiaries) filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code on May 14, 2003. As of the bankruptcy filing date, the Debtor’s financial records were closed for the prepetition period. As required by SOP 90-7 “Financial Reporting by Entities in Reorganization under the Bankruptcy Code,” below are the condensed combined financial statements of the Debtors since the date of the bankruptcy filings (the Debtors’ Statements). The Debtors’ Statements have been prepared on the same basis as NRG Northeast’s Consolidated Financial Statements. All entities of NRG Northeast are included in the bankruptcy filing; therefore the condensed combined balance sheet is not required under SOP 90-7.


	For the three			For the period
	months ended			from May 15, 2003
(In thousands)	September 30, 2003			to September 30, 2003

Operating revenue	$	260,472		$	388,391
Operating costs and expenses		181,351			325,614
Restructuring professional fees and expenses		515			1,081

Operating income		78,606			61,696
Restructuring interest income		2			5
Other expense, net		(14,627	)		(21,833	)

Net income	$	63,981		$	39,868


	For the period
	from May 15, 2003
(In thousands)	to September 30, 2003

Net cash used by operating activities	$	(11,105	)
Net cash used by investing activities		(7,869	)
Net cash used by financing activities		—

Net decrease in cash and cash equivalents		(18,974	)
Cash and cash equivalents at beginning of period		19,100

Cash and cash equivalents at end of period	$	126

As of September 30, 2003, NRG Energy has failed to make scheduled payments on interest and/or principal on approximately $4.0 billion of its recourse debt and is in default under the related debt instruments. These missed payments also have resulted in cross-defaults of numerous other non-recourse and limited recourse debt instruments of NRG Energy. In addition to the missed debt payments, a significant amount of NRG Energy’s debt and other obligations contain terms, which require that they be supported with letters of credit or cash collateral following a ratings downgrade. As a result of the downgrades that NRG Energy experienced in 2002, NRG Energy estimates that it is in default of its obligations to post collateral of approximately $1.2 billion, principally to fund a $842.5 million equity guarantee associated with its construction revolver financing facility, to fund debt service reserves and other guarantees related to NRG Energy projects and to fund trading operations.

Absent an agreement on a comprehensive restructuring plan, NRG Energy will remain in default under its debt and other obligations, because it does not have sufficient funds to meet such requirements and obligations. There can be no assurance that NRG Energy’s creditors ultimately will accept any consensual restructuring plan under the bankruptcy process. For more information about NRG Energy’s restructuring process, refer to the Form 10-K filed by NRG Energy on March 31, 2003, Forms 10-Q filed by NRG Energy on May 20, 2003 August 14, 2003 and November 13, 2003.

NRG Energy and certain of its subsidiaries have negotiated a Senior Secured, Super-Priority Debtor-in-Possession Credit Agreement (the DIP Agreement) with General Electric Capital Corporation (GECC), which was executed following the filing of the petition in NRG Energy’s Chapter 11 bankruptcy case. Under the DIP Agreement, GECC has agreed to make up to $250 million (the DIP Facility) available for working capital and general corporate needs of the Debtors that comprise NRG’s Northeast generating facilities (the DIP Borrowers). The DIP Facility is secured by a first priority lien on substantially all of the assets of and equity interest in the DIP Borrowers, plus the assets of Power Marketing, Inc. that relate to the revenues of the DIP Borrowers.

The DIP Facility bears an interest rate of 2.00% over the prime rate or 3.50% over the LIBOR rate and is currently set to expire on May 13, 2004. NRG Energy does not currently anticipate that it will seek to extend the DIP Facility beyond May 13, 2004. However, should the DIP Facility be extended for more than one year, approval of such financing by New York Public Service Commission will be required as certain NRG Energy assets securing the loan are located in New York. Should such approval be necessary, NRG Energy intends to make a timely application for the approval.

The amount available under the DIP Facility may vary from time to time, depending on valuations of the collateral securing the DIP Facility and GECC’s right to set aside certain reserves. The DIP Facility currently permits the DIP Borrowers to borrow up to $210 million. The total availability may increase to $250 million upon the occurrence of certain subsequent events. A final order approving the DIP Facility was entered by the Bankruptcy Court on July 24, 2003. Such order provides, among other things, that the borrowers may not use DIP funds or cash collateral to make disbursements to, or for the benefit of the Connecticut Light and Power Company, unless further agreed to by GECC, the DIP lender, the Official Committee of Unsecured Creditors of NRG Energy, Inc. et al. and the informal committee of holders of the three series of Senior Secured Bonds issued by NRG Northeast Generating LLC, or further order of the Bankruptcy Court

As of September 30, 2003, there was no amount outstanding under the DIP Facility. As of September 30, 2003, under the DIP Facility, the Company paid a facility fee of approximately $0.9 million. In addition, the Company pays a commitment fee based on utilization of the facility of between 0.5% and 1.0% of the unused commitments of $210 million.

The DIP Facility contains covenants which restrict; mergers and acquisitions, the incurrence of additional debt, the creation of liens, sale of stock and assets, sale-leasebacks, cancellation of indebtedness constituting collateral or subordinated debt, restricted payments, speculative transactions, maximum annual capital expenditures and minimum quarterly earnings as outlined in the DIP Agreement.

In addition, the DIP Facility includes the following reporting covenants; provide monthly financial statements and operating reports within 30 days, provide quarterly financial statements and operating reports within 45 days, provide annual audited financial statements within 90 days of the end of the Company’s fiscal year; provide operating plan within 30 days of fiscal year end, provide management letter and notices described in the DIP Agreement when available or as reasonable requested by the DIP Lenders.

Inventory consisted of spare parts, coal, fuel oil and kerosene and is stated at the lower of weighted average cost or market value:

Property, plant and equipment are stated at cost or recoverable value. Depreciation is computed on a straight-line basis over the following estimated useful lives:

In light of economic developments related to the Connecticut assets and NRG Energy’s application for cost of service reimbursements, The Company reassessed the asset lives for the Connecticut facilities. The shorter depreciable lives resulted in an increase in depreciation of approximately $0.7 million and $13.9 million for the three and nine months ended September 30, 2003. In accordance with SFAS No. 144, the Company has reclassified the accumulated depreciation recorded on those facilities that were impaired during the nine and twelve months ended September 30, 2003 and December 31, 2002, respectively.

On June 18, 2003, the Company terminated an indemnity agreement between itself and NRG PMI, effective to May 14, 2003. Upon the effective termination of this agreement, certain outstanding trade receivables were transferred from the Company to NRG PMI. This transfer resulted in a balance sheet reclass of approximately $67.4 million on the Company’s financials from accounts receivable — trade to accounts receivable — affiliate. These receivables relate to three long-term contracts that were directly affected by the termination of this indemnity agreement. As a result, the Company will no longer recognize any revenues or expenses related to these contracts. The affected contracts were the Standard Offer Service contract with CL&P, a long-term contract with Ashland and a long- term contract with EUA. Effective May 14, 2003, NRG PMI will bear the benefits and burdens of these contracts. During the period prior to May 14, 2003 (January 1, 2003 — May 14, 2003), the provisions of the standard offer contracts resulted in an actual operating loss for the Company’s Connecticut facilities of approximately $105.9 million.

In addition, effective with the indemnity agreement termination, the Company has reclassified certain other accounts receivable — trade balances to accounts receivable — affiliate to recognize the related party relationship between NRG PMI and the Company and its subsidiaries. As of June 30, 2003, approximately $1.7 million of accounts receivable — trade was reclassified to accounts receivable — affiliate. The ongoing expense and revenue recognition related to these transactions will remain consistent with the Company’s past policies and procedures. Included in operating revenue is approximately $256.8 million and $314.1 million of related party revenue for the three and nine month periods ending September 30, 2003.

On January 1, 2001, the Company adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (SFAS No. 133), as amended by SFAS No. 137 and SFAS No. 138. SFAS No. 133 requires the Company to record all derivatives on the balance sheet at fair value. Changes in the fair value of non-hedge derivatives are immediately recognized in earnings. Derivatives that have been designated as hedges of assets, liabilities or firm commitments, are accounted for using the fair value method. Changes in the fair value of these instruments are recognized in earnings as offsets to the changes in the fair value of the related hedged assets, liabilities and firm commitments. Derivatives that have been designated as hedges of forecasted transactions are accounted for using the cash flow method. Changes in the fair value of these instruments are deferred and recorded as a component of accumulated other comprehensive income (OCI) until the hedged transactions occur and are recognized in earnings. Reclassifications of the deferred gains and losses are included on the same line of the statement of operations in which the hedged item is recorded. The ineffective portion of the change in fair value of a derivative instrument designated as a cash flow hedge is immediately recognized in earnings. The Company formally assesses both at inception and at least quarterly thereafter, whether the derivatives used in hedging transactions are highly effective in offsetting the changes in either the fair value or cash flows of the hedged item. This assessment includes all components of each derivative’s gain or loss unless otherwise noted. When it is determined that a derivative ceases to be a highly effective hedge, hedge accounting is discontinued.

SFAS No. 133 applies to the Company’s long-term power sales contracts, long-term gas purchase contracts and other energy related commodities financial instruments used to mitigate variability in earnings due to fluctuations in spot market prices, hedge fuel

requirements at generation facilities and protect investments in fuel inventories. At September 30, 2003, the Company had derivative contracts extending through December 2003.

The following table summarizes the effects of SFAS No. 133 on the Company’s OCI balance:


	Three Months Ended					Nine Months Ended
Gains/(Losses)	September 30,					September 30,

(In thousands)	2003		2002			2003			2002

Beginning Balance	$	—	$	66,772		$	28,835		$	107,741
Unwound from OCI during period:- due to unwinding of previously deferred amounts		—		(2,854	)		(28,835	)		(6,779	)
Mark to market hedge contracts		—		21,889			—			(15,155	)

Ending Balance	$	—	$	85,807		$	—		$	85,807

Gains/(Losses) expected to unwind from OCI during next 12 months	$	—	$	85,807		$	—		$	85,807

Gains of $0 and $28.8 million were reclassified from OCI to current period earnings during the three and nine months ended September 30, 2003 due to the unwinding of one long-term energy commodity contract accounted for as a cash flow hedge, which expired June 30, 2003. In comparison for the three and nine months ended September 30, 2002 gains of approximately $2.9 million and $6.8 million were reclassified. These amounts are recorded on the same line item in the statement of operations in which the hedged items are recorded. During the three and nine months ended September 30, 2003, the Company recorded no amounts in OCI related to changes in the fair values of derivatives accounted for as hedges. For the three and nine months ended September 30, 2002 the Company recorded a gain of $21.9 million and a loss of $15.2 million respectively in OCI, related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of September 30, 2003 was $0. The Company expects no deferred net gains on derivative instruments accumulated in OCI to be recognized as earnings during the next twelve months.

The following table summarizes the effects of SFAS No. 133 on the Company’s statement of operations:

During the three and nine months ended September 30, 2003 and 2002, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

The Company’s earnings for the three months ended September 30, 2003 and 2002 were decreased by an unrealized loss of $3.3 million and $52.8 million, respectively. For the nine months ended September 30, 2003 and 2002 the company’s earnings changed by an unrealized gain of $16.4 million and an unrealized loss of $8.6 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

NRG Energy is impacted by market rule and tariff changes in the existing markets operated by Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs).

On March 1, 2003, ISO-New England implemented its version of Standard Market Design. This change dramatically modifies the New England market structure by incorporating Locational Marginal Pricing (pricing by location rather than on a New England wide basis). While the ISO-New England Standard Market Design represents a significant improvement to the existing market design, NRG Energy still considered the market insufficient to allow NRG Energy to recover its reasonable costs and earn a reasonable return on investment. Therefore, and notwithstanding the impending implementation of Locational Marginal Pricing, on February 26, 2003, NRG Energy filed a proposed cost of service agreement with the Federal Energy Regulatory Commission (FERC) for the following Connecticut facilities: Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and Devon Power LLC units 11-14 (collectively the NRG Subsidiaries). In the filing, NRG Energy requested that major and minor maintenance expenses of the NRG Subsidiaries be paid for through a tracking mechanism that would insure that NRG Energy receives compensation only for actual maintenance expenses. Under the proposed cost of service agreement, the other NRG Energy costs would be paid through a monthly cost-based payment. NRG Energy requested an effective date of February 27, 2003.

On March 25, 2003, FERC issued an order (the March Order) approving the recovery of the NRG Subsidiaries’ Spring 2003 maintenance expenses, subject to refund and authorized an effective date of February 27, 2003. FERC did not rule on the remainder of the issues to allow further time to consider protests.

On April 25, 2003, the FERC issued an order (the April Order) rejecting the remaining part of the proposed cost of service agreements including the monthly cost-based payment. Rather, FERC instructed ISO New England to establish temporary bidding rules that would permit selected peaking units (units with capacity factors of 10 percent or less during 2002), operating within “designated congestion areas” (such as Connecticut) to raise their bids to allow them the opportunity to recover their fixed and variable costs through the market. This temporary bidding rule would remain in place until ISO New England implements locational installed capacity requirements, which should be no later than June 1, 2004. In the July 24 Order on Rehearing (the July Order), FERC clarified that the capacity factor of 10 percent or less applies to units rather than complexes. On a unit basis, all the NRG Energy facilities qualify to bid under the temporary rules except Middletown 2 and 3, and Devon 7 and 8. The existing Reliability Must Run (RMR) agreement between ISO New England and NRG Energy covering Devon 7 and 8 terminated on September 30, 2003. On October 2, 2003, NRG Energy filed to extend the existing RMR agreement. FERC has yet to act on the request to extend the agreement. For additional information regarding the impact that the April 25, 2003 FERC order and other regulatory developments had on NRG Energy’s results of operations, See Note 10.

On October 17, 2003, the Midwest Independent Transmission Operator, Inc. (MISO) filed a motion to withdraw its Open Access Transmission and Energy Market’s Tariff (TEMT), purportedly to allow more time to develop stakeholder consensus on critical outstanding issues relating to market features such as Fixed Transmission Rights, market monitoring and resource adequacy. Post-blackout reliability concerns were also a stated factor for the withdrawal. On October 29, 2003, FERC granted the MISO’s motion. The MISO had planned to phase-in its energy markets during 2004. The withdrawal of the market tariff means that the market will be delayed for an undetermined period of time.

On May 14, 2003, NRG Energy and certain of its affiliates (including NRG Northeast) filed voluntary petitions for reorganization under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court for the Southern District of New York (the Bankruptcy Court), In re: NRG ENERGY, INC., et. al., Case No. 03-13024 (PCB). NRG Energy expects operations to continue as normal during the restructuring process, while it operates its business as a “debtor-in-possession” under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.

Fortistar Capital Inc. v. NRG Energy, Inc., Hennepin County District Court

On July 12, 1999, Fortistar Capital Inc. (Fortistar) sued NRG Energy in Minnesota state court. The complaint sought injunctive relief and damages of over $50 million resulting from NRG Energy’s alleged breach of a letter agreement with Fortistar relating to the

Oswego power plant. NRG Energy asserted counterclaims. After considerable litigation, the parties entered into a conditional, confidential settlement agreement, which was subject to necessary board and lender approvals. NRG Energy was unable to obtain necessary approvals. Fortistar initially moved the court to enforce the settlement, seeking damages in excess of $35 million plus interest and attorneys’ fees. NRG Energy opposed Fortistar’s motion on the grounds that conditions to contract performance had not been satisfied. In July 2003, Fortistar purported to withdraw its motion without prejudice and sought relief from stay at the Bankruptcy Court to liquidate its bankruptcy claim by trying the action in the Minnesota State Court. The Bankruptcy Court denied Fortistar’s relief from stay motion and Fortistar is now seeking relief and review at the United States District Court for the Southern District of New York. NRG Energy cannot predict the outcome of this dispute.

Connecticut Light & Power Company v. NRG Power Marketing Inc., Docket No. 3:01-CV-2373 (A WT), pending in the United States District Court, District of Connecticut

This matter involves a claim by Connecticut Light & Power Company for recovery of amounts it claims are owing for congestion charges under the terms of a Standard Offer Services contract between the parties, dated October 29, 1999. CL&P has served and filed its motion for summary judgment to which NRG Power Marketing Inc. (NRG PMI) filed a response on March 21, 2003. CL&P has withheld approximately $30 million from amounts owed to NRG PMI, claiming that it has the right to offset those amounts under the contract. NRG PMI has counterclaimed seeking to recover those amounts, arguing among other things that CL&P has no rights under the contract to offset them. By reason of the bankruptcy stay, the court has not ruled on the pending motion. On November 6, 2003, the parties filed a joint stipulation for relief from the automatic stay in order to allow the proceeding to go forward. NRG PMI cannot estimate at this time the likelihood of an unfavorable outcome in this matter, or the overall exposure for congestion charges for the full term of the contract.

Connecticut Light & Power Company, Docket No. EL03-135, pending at the Federal Energy Regulatory Commission

This matter involves a dispute between CL&P and NRG PMI concerning which of those parties is responsible, under the terms of the October 29, 1999 Standard Offer Services contract, for costs related to congestion and losses associated with the implementation of standard market design (SMD-Related Costs). CL&P has withheld, beyond the $30 million discussed above, an additional approximately $70 million from amounts owed to NRG PMI, claiming that it is entitled under the contract to offset those additional amounts for SMD-Related Costs. NRG PMI cannot estimate at this time the likelihood of an unfavorable outcome in this matter, or the overall exposure for SMD-Related Costs for the full term of the contract.

Connecticut Light & Power — Related Proceedings at the Federal Energy Regulatory Commission, the United States District Court for the Southern District of New York, and the United States Court of Appeals for the D.C. Circuit and the Second Circuit.

In May, 2003, NRG PMI took steps to terminate or reject in bankruptcy the subject Standard Offer Services contract. CL&P, the Connecticut Attorney General and the Connecticut Department of Public Utility Control (DPUC) sought and obtained from FERC an Order dated May 16, 2003, temporarily requiring NRG PMI to continue to comply with the terms of the contract, pending further notice from FERC. Thereafter, On June 2, 2003, the United States Bankruptcy Court for the Southern District of New York issued its Order specifically authorizing NRG PMI’s rejection of the contract, and by Order dated June 12, 2003, the United States District Court for the Southern District of New York granted NRG PMI’s motion for a temporary restraining order staying all actions by CL&P, the Connecticut Attorney General and the DPUC to enforce or apply the above-referenced FERC Order and affording NRG PMI leave to cease its performance under the contract, effective retroactive to June 2, 2003. FERC then issued an order on June 25, 2003 (June 25 Order), that again commanded NRG PMI’s continued performance regardless of any contrary ruling by the Bankruptcy Court and the District Court’s temporary restraining order. By order dated June 30, 2003, the District Court reversed itself and dismissed NRG PMI’s motion for preliminary injunction for lack of subject matter jurisdiction. On July 18, 2003, NRG PMI appealed to the Second Circuit respecting the District Court’s refusal to enjoin FERC. On August 15, 2003, FERC issued orders denying rehearing of the June 25 Order and requiring NRG PMI to continue to perform under the Standard Offer Services contract (the June 25 Order, together with the August 15 Orders, the “Commission Orders”). NRG PMI filed a request for rehearing with FERC and a petition for review in the United States Court of Appeals for the District of Columbia Circuit in Case No. 03-1346 relating to the Commission Orders. On November 4, 2003, the parties reached a settlement under which the Second Circuit and D.C. Circuit litigation respecting the above matters will be dismissed, while preserving the parties’ rights to litigate those matters which are before the United States District Court for the District of Connecticut and FERC, as previously discussed. The settlement does not affect issues between CL&P and NRG Energy, Inc., related to station service, described hereafter, which will be separately arbitrated. The settlement is subject to regulatory and legal approvals, including approval from FERC and the United States Bankruptcy Court for the Southern District of New York.

The State of New York and Erin M. Crotty, as Commissioner of the New York State Department of Environmental Conservation v. Niagara Mohawk Power Corporation et al., United States District Court for the Western District of New York, Civil Action No. 02-CV-002S

In January 2002, NRG Energy and Niagara Mohawk Power Corporation (NiMo) were sued by the New York Department of Environmental Conservation in federal court in New York. The complaint asserted that projects undertaken at NRG Energy’s Huntley and Dunkirk plants by NiMo, the former owner of the facilities, required preconstruction permits pursuant to the Clean Air Act and that the failure to obtain these permits violated federal and state laws. In July 2002, NRG Energy filed a motion to dismiss. On March 27, 2003 the court dismissed the complaint against NRG Energy with prejudice as to the federal claims and without prejudice as to the state claims. It is possible the state will appeal this dismissal to the Second Circuit Court of Appeals. In the meantime, on April 25, 2003, the state provided to NRG Energy notice of intent to again sue the Company and various affiliates by filing a second amended complaint in this same action in the federal court in New York, asserting against the NRG Defendants violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. The NRG Defendants have moved to dismiss the second amended

complaint, and that motion is now under advisement. If the case ultimately is litigated to a judgment and there is an unfavorable outcome that could not be addressed otherwise, NRG Energy has estimated that the total investment that would be required to install pollution control devices could be as high as $300 million over a ten to twelve-year period.

Niagara Mohawk Power Corporation v. NRG Energy, Inc., Huntley Power, LLC, and Dunkirk Power, LLC, Supreme Court, State of New York, County of Onondaga, Case No. 2001-4372

NRG Energy has asserted that NiMo is obligated to indemnify it for any related compliance costs associated with resolution of the above enforcement action. NiMo has filed suit in state court in New York seeking a declaratory judgment with respect to its obligations to indemnify NRG Energy under the asset sales agreement. NRG Energy has pending a summary judgment motion on its entitlement to be reimbursed by NiMo for the attorneys’ fees NRG Energy has incurred in the enforcement action.

All three of these facilities have been issued Notices of Violation with respect to opacity exceedances. The above entities have been engaged in consent order negotiations with the New York State Department of Environmental Conservation (DEC) relative to opacity issues affecting all three facilities since the plants were acquired. It appears that by year-end, the parties will finalize the terms of a consent order, which will quantify the number of opacity exceedances at the three facilities through the second quarter of 2003 and set a cumulative penalty, presently anticipated to be some $1 million. In the event that the consent order negotiations prove unsuccessful, it is not known what relief the DEC will seek through an enforcement action and what the result of such action will be.

On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the New York Department of Environmental Conservation (DEC) reporting violations of applicable sulfur in fuel limits, which had occurred during 6 days in March 2003 at the chimney stack serving Huntley Units 63-66. The Huntley Station self-disclosed that the average sulfur emissions rates for those days had been 1.8 lbs/mm BTU, rather than the maximum allowance of 1.7 lbs/mm BTU. NRG Huntley Operations discontinued use of Unit 65 (the only unit utilizing the subject stack at the time) and has kept the remaining 3 units off line until adherence with the applicable standard is assured. On May 19, 2003, the DEC issued Huntley Power LLC a Notice of Violation. The Company has met with the DEC to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. The Company does not know what relief the DEC will seek through an enforcement action. Under applicable provisions of the Environmental Conservation Law, the DEC asserts that it may impose a civil penalty up to $10,000, plus an additional penalty not to exceed $10,000 for each day that a violation continues and may enjoin continuing violations.

Niagara Mohawk Power Corporation v. Dunkirk Power LLC, et al., Supreme Court, Erie County, Index No. 1-2000-8681

On October 2, 2000, plaintiff Niagara Mohawk Power Corporation commenced this action against NRG Energy to recover damages plus late fees, less payments received through the date of judgment, as well as any additional amounts due and owing, for electric service provided to the Dunkirk Plant after September 18, 2000. Plaintiff Niagara Mohawk claims that NRG Energy has failed to pay retail tariff amounts for utility services commencing on or about June 11, 1999 and continuing to September 18, 2000 and thereafter. Plaintiff has alleged breach of contract, suit on account, violation of statutory duty, and unjust enrichment claims. On or about October 23, 2000, NRG Energy served an answer denying liability and asserting affirmative defenses.

After proceeding through discovery, and prior to trial, the parties and the court entered into a stipulation and order filed August 9, 2002 consolidating this action with two other actions against NRG Northeast’s Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services.

On October 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action pending submission of some or all of the disputes in the action to the FERC. NRG Energy cannot make an evaluation of the likelihood of an unfavorable outcome. The cumulative potential loss could exceed $35 million.

Niagara Mohawk Power Corporation v. Huntley Power LLC, NRG Huntley Operations, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power LLC, Oswego Harbor Power LLC, and NRG Oswego Operations, Inc., Case Filed November 26, 2002 in Federal Energy Regulatory Commission Docket No. EL 03-27-000.

This is the companion action filed by Niagara Mohawk at FERC, similarly asserting that Niagara Mohawk is entitled to receive retail tariff amounts for electric service provided to the Huntley, Dunkirk and Oswego plants. On October 31, 2003, the FERC Trial Staff, a party to the proceedings, filed a reply brief in which they supported and agreed with each position taken by the NRG Generators in their initial brief. In short, the staff argued that the NRG Generators: (1) self-supply station power under the NYISO tariff (which took effect on April 1, 2003), in any month during which they produce more energy than they consume and, as such should not be assessed a retail rate; (2) are connected only to transmission facilities and as such, at most should only pay NiMo a FERC-approved transmission rate; and (3) should be allowed to net consumption and output even if power is injected into the grid at a different point from which it is drawn off. The parties are currently engaged in settlement negotiations which, should they prove successful, will resolve both this FERC action and the above-referenced state court proceedings respecting amounts owing for electrical service provided to these three plants. At this stage of the proceedings, we cannot estimate the likelihood of an adverse determination. As noted above, the cumulative potential loss could exceed $35 million.

NRG Energy and various of its subsidiaries are in default under various of their credit facilities, financial instruments, construction agreements and other contracts, which have given rise to liens, claims and contingencies against them and may in the future give rise to additional liens, claims and contingencies against them. In addition, NRG Energy and various of its subsidiaries have entered into various guarantees, equity contribution agreements, and other financial support agreements with respect to the obligations of their affiliates, which have given rise to liens, claims and contingencies against them and may in the future give rise to additional liens, claims and contingencies against the party or parties providing the financial support. NRG Energy cannot predict the outcome or financial impact of these matters.

The Company is directly liable for the obligations of certain of its subsidiaries pursuant to guarantees relating to certain of their operating obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of the Company’s generation facilities in the United States, the Company may be required to guarantee a portion of the obligations of certain of its subsidiaries. As of September 30, 2003, the Company’s obligations pursuant to its guarantees of the performance of its subsidiaries totaled approximately $35.3 million.

As a result of the changing operational, regulatory and financial conditions impacting the Company on an ongoing basis, the Company reviews the recoverability of its long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, the Company recorded asset impairment charges of $9.0 million for the three months ended September 30, 2003 and $230.6 million for the nine months ended September 30, 2003, as shown in the table below.

To determine whether an asset was impaired NRG Northeast compared asset carrying values to total future estimated undiscounted cash flows. Separate analyses were completed for assets or groups of assets at the lowest level for which identifiable cash flows were largely independent of the cash flows of other assets and liabilities. The estimates of future cash flows included only future cash flows, net of associated cash outflows, directly associated with and expected to arise as a result of the Company’s assumed use and eventual disposition of the asset. Cash flow estimates associated with assets in service were based on the asset’s existing service potential. The cash flow estimates may include probability weightings to consider possible alternative courses of action and outcomes, given the uncertainty of available information and prospective market conditions.

If an asset was determined to be impaired based on the cash flow testing performed, an impairment loss was recorded to write down the asset to its fair value. Estimates of fair value were based on prices for similar assets and present value techniques. Fair values determined by similar asset prices reflect the Company’s current estimate of recoverability from expected marketing of project assets. For fair values determined by projected cash flows, the fair value represents a discounted cash flow amount over the remaining life of each project that reflects project-specific assumptions for long-term power pool prices, escalated future project operating costs, and expected plant operation given assumed market conditions.

Asset impairments and restructuring charges from continuing operations included in operating expenses in the Consolidated Statements of Operations include the following:

Connecticut Facilities - NRG Energy reviewed cash flow models for its Connecticut generating facilities at December 31, 2002. No impairment was required based on the pricing and cost recovery assumptions at December 31, 2002. On February 26, 2003 NRG Energy filed a proposed cost of service agreement for the following Connecticut facilities with the Federal Energy Regulatory Commission (FERC) Devon 11-14, Middletown station, Montville station, Norwalk Harbor station. On April 25, 2003, the FERC issued an order that rejected NRG Energy’s proposed fixed monthly charges, citing certain policy determinations regarding cost-of-service agreements. FERC instead directed NRG Energy to recover its fixed and variable costs under interim bidding rules for generators located in constrained areas, the so-called Peaking Unit Safe Harbor (PUSH) mechanism. The PUSH bidding rules would apply to all of NRG Energy’s Connecticut facilities that filed the proposed cost of service agreements, with the exception of Middletown Units 2 and 3, until June 1, 2004. The following quick start facilities, located in Connecticut also have submitted PUSH bids that have been approved by FERC: Cos Cob, Franklin Drive, Branford and Torrington. FERC also ordered that the regional power agencies overseeing the energy markets in Connecticut, the Independent System Operator for New England (ISO-NE) and the New England Power Pool (NEPOOL), modify the New England market rules to establish and implement locational capacity or deliverability requirements no later than June 1, 2004. In late May and June 2003, ISO-NE revised its market pricing rules to facilitate FERC’s mandated PUSH mechanism, but has not yet proposed the market modifications required to implement locational capacity or deliverability requirements. In June 2003 NRG Energy filed for rehearing of several elements of FERC’s April 25, 2003 order. In response, on July 25, 2003, FERC re-affirmed the PUSH interim pricing mechanism.

The existing RMR between ISO-NE and NRG Energy covering Devon 7 and 8 terminated on September 30, 2003. On October 2, 2003, NRG filed to extend the existing RMR agreements. A number of protests have been filed and FERC has yet to act on the request to extend the agreements.

As a result of these regulatory developments and changing circumstances in the second quarter of 2003, NRG Energy updated the facilities’ cash flow models to incorporate changes to reflect the impact of the April 25, 2003 FERC’s orders on PUSH pricing, the pending termination of the RMR, and to update the estimated impact of future locational capacity or deliverability requirements. Based on these revised cash flow models, management determined that the new estimates of pricing and cost recover levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003 NRG Energy recorded a $64.2 million and $157.3 million impairment at Devon Power LLC and Middletown Power LLC, respectively. NRG Energy accounts for the results of operations of the Connecticut Facilities as part of its power generation segment within North America.

Arthur Kill Power, LLC - During the third quarter of 2003 NRG Energy cancelled its plans to re-establish fuel oil capacity at its Arthur Kill plant. This resulted in a charge of approximately $9.0 million to write-off assets under development.

Credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced by the Company during the third quarter of 2002 were “triggering events” which required NRG Northeast to review the recoverability of its long-lived assets. Adverse economic conditions resulted in declining energy prices. As a result, the Company determined that Somerset Power, became impaired during the third quarter of 2002 and should be written down to fair market value. During 2002, the Company recorded impairment charges of $49.3 million.

During the three and nine month periods ended September 30, 2003, the Company incurred $0.5 million and $2.8 million, respectively, of restructuring costs consisting of advisor fees. These costs consist of employee separation costs and advisor fees. There were no restructuring costs during 2002.

Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143). SFAS No. 143 requires an entity to recognize the fair value of a liability for an asset retirement obligation in the period in which it is incurred. Upon initial recognition of a liability for an asset retirement obligation, an entity shall capitalize an asset retirement cost by increasing the carrying amount of the related long-lived asset by the same amount as the liability. Over time, the liability is accreted to its present value each period, and the capitalized cost is depreciated over the useful life of the related asset. Retirement obligations associated with long-lived assets included within the scope of SFAS No. 143 are those for which a legal obligation exists under enacted laws, statutes and written or oral contracts, including obligations arising under the doctrine of promissory estoppel.

The Company has identified certain retirement obligations at Somerset Power LLC, a wholly owned subsidiary of the Company, related primarily to future environmental obligations. The Company has also identified other asset retirement obligations that could not be calculated because the assets associated with the retirement obligations were determined to have an indeterminate life. The adoption of SFAS No. 143 resulted in recording a $0.2 million increase to property, plant and equipment and a $0.3 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was approximately a $0.1 million increase to depreciation expense and approximately a $0.1 million increase to operating expenses.

The following represents the balances of the asset retirement obligation as of January 1, 2003 and the additions and accretion of the asset retirement obligation for the nine months ended September 30, 2003:

The following represents the pro-forma effect on the Company’s net income for the three and nine months ended September 30, 2002, as if the Company had adopted SFAS No. 143 as of January 1, 2002:

In April 2002, the FASB issued SFAS No. 145, “Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections”, that supersedes previous guidance for the reporting of gains and losses from extinguishment of debt and accounting for leases, among other things. SFAS No. 145 requires that only gains and losses from the extinguishment of debt that meet the requirements for classification as “Extraordinary Items,” as prescribed in Accounting Practices Board Opinion No. 30, should be disclosed as such in the financial statements. Previous guidance required all gains and losses from the extinguishment of debt to be classified as “Extraordinary Items.” This portion of SFAS No. 145 is effective for fiscal years beginning after May 15, 2002, with restatement of prior periods required. The Company adopted this standard as of January 1, 2003 and has no extraordinary gains or losses that will require restatement.

In addition, SFAS No. 145 amends SFAS No. 13, “Accounting for Leases”, as it relates to accounting by a lessee for certain lease modifications. Under SFAS No. 13, if a capital lease is modified in such a way that the change gives rise to a new agreement classified as an operating lease, the assets and obligation are removed, a gain or loss is recognized and the new lease is accounted for as an operating lease. Under SFAS No. 145, capital leases that are modified so the resulting lease agreement is classified as an operating lease are to be accounted for under the sale-leaseback provisions of SFAS No. 98, “Accounting for Leases”. These provisions of SFAS No. 145 were effective for transactions occurring after May 15, 2002. SFAS No. 145 will be applied as required. Adoption of SFAS No. 145 is not expected to have a material impact on the Company.

In June 2002, the FASB issued SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” (SFAS No. 146). SFAS No. 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and nullifies EITF Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring).” SFAS No. 146 applies to costs associated with an exit activity that does not involve an entity newly acquired in a business combination or with a disposal activity covered by SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” The provisions of SFAS No. 146 are effective for exit or disposal activities that are initiated after December 31, 2002. SFAS No. 146 will be applied as required.

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities”, (FIN No. 46). FIN No. 46 requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidation of variable interest entities with which it has similar relationships but no majority voting interest. Under FIN No. 46 the voting interest approach is not effective in identifying controlling financial interest. The new rule requires that for entities to be consolidated that those assets be initially recorded at their carrying amounts at the date the requirements of the new rule first apply. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value the first date the new rule applies. Any difference between the net amount of any previously recognized interest in the newly consolidated entity should be recognized as the cumulative effect of an accounting change. FIN No. 46 becomes effective in the first interim or annual period ending after December 15, 2003. FIN No. 46 will be applied as required and is not expected to have a material impact on the Company.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”, (SFAS No. 149). SFAS No. 149 amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities.” The provisions of SFAS No. 149 are effective for contracts entered into or modified after June 30, 2003 and for hedging relationships designated after June 30, 2003. In addition, provisions of SFAS 149 that relate to SFAS Statement No. 133 Implementation Issues that have been effective for fiscal quarters that began prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. SFAS No. 149 has not had an impact on the Company.

In May 2003, the FASB issues SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”, (SFAS No. 150). SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is

within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. The provisions of SFAS 150 are effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. SFAS No. 150 has not had a material impact on the Company.

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

NRG Northeast is a wholly-owned indirect subsidiary of NRG Energy. NRG Energy is a leading independent power production company, primarily engaged in the ownership and operation of power generation facilities and the sale of energy, capacity and related products in the United States. While NRG Energy is currently an indirect, wholly owned subsidiary of Xcel Energy, it will be an independent public company upon its emergence from bankruptcy and will no longer have any material affiliation or relationship with Xcel Energy. NRG Energy has a diverse generation portfolio in terms of geography, fuel type and dispatch levels. NRG Energy believes this diversity helps balance risk and increase profits. NRG Northeast owns electric power generation plants in the northeastern region of the United States. As part of NRG Energy’s strategy, NRG Northeast intends to maximize operating income through the efficient procurement and management of fuel supplies, transportation and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

NRG Energy and the Company do not anticipate any significant new acquisitions or construction in the near future, and instead will focus on operational performance, asset management and debt reduction. The Company has already made significant reductions in capital expenditures, business development activities and personnel. Power sales, fuel procurement and risk management will remain a key strategic element of the Company’s operations. The Company’s objective will be to optimize the operating income of its facilities within an appropriate risk and liquidity profile.

Industry Trends. In this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” management discusses the Company’s historical results of operations. During 2003, the following factors, among others, have negatively affected the Company’s results of operations:

•

a narrowing of the “spark spread” (the difference between power prices and fuel costs) in most regions of the United States in which the Company’s operates power generation facilities;

•

mild weather during peak seasons in regions where the Company has significant merchant capacity;

•

reduced liquidity in the energy trading markets as a result of fewer participants trading lower volumes;

•

the imposition of price caps and other market mitigation in markets where the Company has significant merchant capacity;

•

regulatory and market frameworks in certain markets where the Company operates that prevents the Company from charging prices that will enable the Company to recover its operating costs and to earn acceptable returns on capital;

•

the obligation to perform under certain long-term contracts that are not profitable;

•

physical, regulatory and market constraints on transmission facilities in certain regions that limit or prevents the Company from selling power generated by certain of its facilities;

•

limited access to capital due to the Company’s financial condition since July 2002, and the resulting contraction of the Company’s ability to conduct business in the merchant energy markets; and

•

changes and turnover in senior and middle management since June 2002 in connection with the Company’s restructuring.

The Company expects that weak market conditions will continue through 2003 and 2004, and into 2005 in some markets. Historically, the Company believed that, as supply surpluses begin to tighten and as market rules and regulatory conditions stabilize, prices will improve for energy, capacity and ancillary services. This view is consistent with the Company’s belief that in the long run market prices will support an adequate rate of return on the construction of new power generation assets needed to meet increasing demand. This view is currently being challenged in certain markets as regulatory actions and market rules unfold that limit the ability of merchant power companies to earn favorable returns on existing and new investments. To the extent unfavorable regulatory and market conditions exist in the long term, the Company could have significant impairments of property, plant and equipment and goodwill which, in turn, could have a material adverse effect on results of operations.

New Management. On October 21, 2003, NRG Energy announced the appointment of David W. Crane as its new President and Chief Executive Officer, effective December 1, 2003. Before joining NRG Energy, Mr. Crane served as the Chief Executive Officer of London-based International Power and has over 12 years of energy industry experience. During 2003, NRG Energy also hired several key senior and middle management positions. Currently it is conducting a search for a new Chief Financial Officer and anticipates the position will be filled in the months following its emergence from bankruptcy. Upon emergence from bankruptcy, NRG Energy’s board of directors will consist of Mr. Crane and ten other individuals, six of whom will initially be designated by the members of the noteholder group serving on the creditors’ committee and four of whom will initially be designated by representatives of NRG Energy’s bank creditors.

Independent Public Accountants; Audit Committee. PricewaterhouseCoopers LLP have been our independent auditors since 1995. In connection with the appointment of a new board of directors upon our emergence from bankruptcy, we will have an audit committee consisting of independent directors. The committee will oversee the Company’s independent auditor relationship and will evaluate from time to time whether the Company will be best served by a change in independent auditors. The audit committee’s evaluation process is intended to ensure that we will continue to have high-quality, cost-efficient independent auditing services.

For the three months ended September 30, 2003 compared to the three months ended September 30, 2002

Total operating revenues were $260.5 million and $233.6 million for the three months ended September 30, 2003 and 2002, respectively, an increase of $26.9 million or 11.5%. This increase is primarily due to increased generation revenue. Higher natural gas prices resulted in a higher price per MW hour generated. The effect of higher power prices was offset by lower generation. Gas fired plants had lower generation due to the adverse price effect of natural gas. Cooler than expected summer temperatures resulted in reduced generation at other plants. In addition, subsequent to May 14, 2003, the Company ceased to recognize any revenues or expenses related to the Standard Offer Service contract with CL&P, a long-term contract with Ashland and a long-term contract with EUA. This is due to the termination of an indemnity agreement between the Company and NRG PMI, a wholly owned subsidiary of NRG Energy and an affiliate of the Company. Effective May 14, 2003, NRG PMI will bear the benefits and burdens of these contracts.

Operating costs primarily consist of expenses for fuel, plant operations and maintenance, property and other non-income related taxes and unrealized gains or losses associated with changes in the fair value of energy related derivative instruments not accounted for as hedges.

Operating costs were $145.4 million for the three months ended September 30, 2003 compared to $182.1 million for the three months ended September 30, 2002. This represents a decrease of $36.7 million or 20.2% for the three months ended September 30, 2003 compared to the same periods in 2002. This decrease is due to reduced fuel costs as a result of decreased generation, partially offset by an increase in fuel oil and natural gas prices.

Depreciation expense was $14.3 million and $13.6 million for the three months ended September 30, 2003 and 2002, respectively. In light of economic developments related to the Connecticut assets and the FERC issued order regarding cost of service reimbursements, the Company reassessed the asset lives for the Connecticut facilities during 2003. The shorter depreciable lives resulted in an increase in depreciation expense. This increase was offset by reduced depreciable values resulting from asset impairment charges on the Connecticut assets during the second quarter of 2003.

General and administrative expense was $12.6 million and $5.3 million for the three months ended September 30, 2003 and 2002, respectively, an increase of $7.3 million or 137.7%. General and administrative costs include non-operational labor and other employee related costs, as well as outside services, insurance, office expenses and administrative support. During the third quarter of 2003, NRG Energy and NRG PMI began allocating certain overhead expenses down to the project level. In addition, insurance expense increased due to an overall increase in insurance premiums.

Restructuring and impairment charges were $9.6 million and $49.3 million for the three months ended September 30, 2003 and 2002, respectively. Asset impairment charges were $9.0 million and $49.3 million for the three months ended September 30, 2003 and 2002, respectively. Restructuring costs were $0.5 million for the three months ended September 30, 2003. There were no restructuring costs incurred during the three months ended September 30, 2002.

Asset impairments for the three months ended September 30, 2003 consisted of the cancellation of a fuel oil capacity project at one of the Company’s subsidiaries.

Credit rating downgrades, defaults under certain credit agreements, increased collateral requirements and reduced liquidity experienced by the Company during the third quarter of 2002 were “triggering events” which required NRG Northeast to review the recoverability of its long-lived assets. Adverse economic conditions resulted in declining energy prices. As a result, the Company determined that Somerset Power, LLC, became impaired during the third quarter of 2002 and should be written down to fair market value. During 2002, the Company recorded impairment charges of $49.3 million.

During the three months ended September 30, 2003, the Company incurred $0.5 million of restructuring costs consisting primarily of employee separation costs and advisor fees.

Interest expense was $14.6 million and $12.9 million for the three months ended September 30, 2003 and 2002, respectively, an increase of $1.7 million or 13.2%. Interest expense includes amortization of deferred finance costs, interest on the senior secured bonds issued on February 22, 2000 and an affiliated note payable issued on June 15, 2002. After the bankruptcy filing the Company entered into a Senior Secured, Super-Priority (Debtor-in-Possession Credit Agreement), which costs are being amortized starting May 14, 2003.

For the nine months ended September 30, 2003 compared to the nine months ended September 30, 2002

Total operating revenues were $603.9 million and $550.3 million for the nine months ended September 30, 2003 and 2002, respectively, an increase of $53.6 million or 9.7%. This increase is primarily due to increased generation revenue. Gas fired plants had lower generation due to the adverse price effect of natural gas. Cooler than expected summer temperatures resulted in reduced generation at other plants. In addition subsequent to May 14, 2003, the Company ceased to recognize any revenues or expenses related to the Standard Offer Service contract with CL&P, a long term contract with Ashland and a long term contract with EUA. This is due to the termination of an indemnity agreement between the Company and NRG PMI, a wholly owned subsidiary of NRG Energy and an affiliate of the Company. Effective May 14, 2003, NRG PMI will bear the benefits and burdens of these contracts. Although there were continued losses incurred on the Connecticut Standard Offer and other contract obligations due to increased market prices, these losses were borne by NRG PMI subsequent to May 14, 2003.

Cost of operations was $500.6 million for the nine months ended September 30, 2003 compared to $390.7 million for the nine months ended September 30, 2002. This represents an increase of $109.9 million or 28.1% for the nine months ended September 30, 2003 compared to the same period in 2002. Although generation declined for the nine-month period ended September 30, 2003 compared to the same period in 2002, the cost of generation increased substantially due to increased fuel oil and natural gas prices. In addition, as a result of the Company’s financial condition, various parties exercised their rights to terminate commodity purchase and sales contracts, which resulted in several contract terminations during the three months ended September 30, 2003. As a result, contract termination expense of $53.5 million was recorded. Offsetting this expense was a favorable change in the fair value of the Company’s energy related derivatives directly resulting from the termination of these contracts.

Depreciation expense was $51.1 million and $39.8 million for the nine months ended September 30, 2003 and 2002, respectively, an increase of $11.3 million or 28.4%. In light of economic developments related to the Connecticut assets and the FERC issued order regarding cost of service reimbursements, The Company reassessed the asset lives for the Connecticut facilities during 2003. The shorter depreciable lives resulted in an increase in depreciation expense. This increase was offset by reduced depreciable values resulting from asset impairment charges on the Connecticut assets during the second quarter of 2003.

General and administrative expense was $29.9 million and $16.7 million for the nine months ended September 30, 2003 and 2002, respectively, an increase of $13.2 million or 79.0%. During the third quarter of 2003, NRG Energy and NRG PMI began allocating certain overhead expenses down to the project level. Insurance expense increased due to an overall increase in insurance premiums. In addition, the company recorded $6.2 million of bad debt expense during the first quarter of 2003 for collectibility issues primarily related to one contract.

Restructuring and impairment charges were $233.4 million and $49.3 million for the nine months ended September 30, 2003 and 2002, respectively. Asset impairment charges were $230.5 million and $49.3 million for the nine months ended September 30, 2003 and 2002, respectively. Restructuring costs were $2.8 million for the nine months ended September 30, 2003. There were no restructuring costs incurred during the nine months ended September 30, 2002.

Asset impairments for the nine-month period ended September 30, 2003 consisted of Devon Power LLC, Middletown Power LLC and a cancelled construction project at one of the Company’s subsidiaries. On February 26, 2003, NRG Energy filed a proposed cost-of-service agreement for the following Connecticut facilities with the Federal Energy Regulatory Commission (FERC): Devon 11-14, Middletown station, Montville station and Norwalk Harbor station. On April 25, 2003, the FERC issued an order that rejected NRG Energy’s proposed fixed monthly charges, citing certain policy determinations regarding cost-of-service agreements. FERC instead directed NRG Energy to recover its fixed and variable costs under interim bidding rules for generators located in constrained areas, the so-called Peaking Unit Safe Harbor (PUSH) mechanism. The PUSH bidding rules would apply to all of NRG Energy’s Connecticut facilities that filed the proposed cost-of-service agreements, with the exception of Middletown Units 2 and 3, until June 1, 2004. The following quick start facilities, located in Connecticut also have submitted PUSH bids that have been approved by FERC: Cos Cob, Franklin Drive, Branford and Torrington. FERC also ordered that the regional power agencies overseeing the energy markets in Connecticut, the Independent System Operator for New England (ISO-NE) and the New England Power Pool (NEPOOL), modify the New England market rules to establish and implement locational capacity or deliverability requirements no later than June 1, 2004. In late May and June 2003, ISO-NE revised its market pricing rules to facilitate FERC’s mandated PUSH mechanism, but has not yet proposed the market modifications required to implement locational capacity or deliverability requirements. In June 2003, NRG Energy filed for rehearing of several elements of FERC’s April 25, 2003 order. In response, on July 25, 2003, FERC re-affirmed the PUSH interim pricing mechanism.

Based on these revised cash flow models, management determined that the new estimates of pricing and cost recovery levels were not projected to return sufficient revenue to cover the fixed costs at Devon Power LLC and Middletown Power LLC. As a consequence, during the second quarter of 2003 NRG Energy recorded a $64.2 million and $157.3 million impairment at Devon Power LLC and Middletown Power LLC, respectively.

During the third quarter of 2003 NRG Energy cancelled its plans to re-establish fuel oil capacity at one of the Company’s subsidiaries. This resulted in a charge of approximately $9.0 million to write-off assets under development.

During the nine months ended September 30, 2003, the Company incurred $1.1 million, of restructuring costs consisting of employee separation costs and advisor fees.

NRG Energy is impacted by market rule and tariff changes in the existing markets operated by Independent System Operators (ISOs) and Regional Transmission Organizations (RTOs). On March 1, 2003, ISO-New England implemented its version of Standard Market Design. This change dramatically modifies the New England market structure by incorporating Locational Marginal Pricing (pricing by location rather than on a New England wide basis). While the ISO-New England Standard Market Design represents a significant improvement to the existing market design, NRG Energy still considered the market insufficient to allow NRG Energy to recover its reasonable costs and earn a reasonable return on investment. Therefore, and notwithstanding the impending implementation of Locational Marginal Pricing, on February 26, 2003, NRG Energy filed a proposed cost-of-service agreement with FERC for the following Connecticut facilities: Middletown Power LLC, Montville Power LLC, Norwalk Power LLC and Devon Power LLC units 11-14 (collectively the NRG Subsidiaries). In the filing, NRG Energy requested that major and minor maintenance expenses of the NRG Subsidiaries be paid for through a tracking mechanism that would insure that NRG Energy receives compensation only for actual maintenance expenses. Under the proposed cost-of-service agreement, the other NRG Energy costs would be paid through a monthly cost-based payment. NRG Energy requested an effective date of February 27, 2003.

On April 25, 2003, the FERC issued an order (the April Order) rejecting the remaining part of the proposed cost-of-service agreements including the monthly cost-based payment. Rather, FERC instructed ISO New England to establish temporary bidding rules that would permit selected peaking units (units with capacity factors of 10 percent or less during 2002), operating within “designated congestion areas” (such as Connecticut) to raise their bids to allow them the opportunity to recover their fixed and variable costs through the market. This temporary bidding rule would remain in place until ISO New England implements locational installed capacity requirements, which should be no later than June 1, 2004. In the July 24 Order on Rehearing (the July Order), FERC clarified that the capacity factor of 10 percent or less applies to units rather than complexes. On a unit basis, all the NRG Energy facilities qualify to bid under the temporary rules except Middletown 2 and 3, and Devon 7 and 8. The RMR agreement between ISO New England and NRG Energy covering Devon 7 and 8 terminated on September 30, 2003. On October 2, 2003, NRG Energy filed the existing RMR agreement. FERC has yet to act on the request to extend the agreement.

Interest expense was $40.3 million and $39.6 million for the nine months ended September 30, 2003 and 2002, respectively, an increase of $0.7 million or 1.8%. This increase is due to the additional interest costs related to the affiliated note payable and

amortization of deferred finance costs related to the Debtor-in Possession Agreement.

Management’s discussion and analysis of its financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles requires the application of appropriate technical accounting rules and guidance as well as the use of estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses. These judgments, in and of themselves, could materially impact the financial statements and disclosures based on varying assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the financial statements and related disclosures, even if the nature of the accounting policies have not changed.

On an ongoing basis, the Company evaluates its estimates utilizing historic experience, consultation with experts and other methods the Company considers reasonable. In any case, actual results may differ significantly from the Company’s estimates. Any effects on the Company’s business, financial position or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Refer to Item 15 Note 2 of the consolidated financial statements of the Company’s Form 10-K for the year ended December 31, 2002 for additional discussion regarding the Company’s accounting policies and estimates.

Liquidity Issues of NRG Energy and it Subsidiaries — Current Status and Chain of Events

Subsequent to the Petition Date, additional NRG Energy subsidiaries filed petitions for reorganization with the Bankruptcy Court. On June 5, 2003 NRG Nelson Turbines LLC and LSP-Nelson Energy LLC (both wholly owned subsidiaries of NRG Energy) filed voluntary petitions for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court. On August 19, 2003, NRG McClain LLC (a wholly owned subsidiary of NRG Energy) filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court.

The Plan Debtors commenced solicitation of votes on the Plan on October 14, 2003. The voting deadline by which holders of claims and equity interests of the Plan Debtors must submit their ballots accepting or rejecting the Plan is November 12, 2003. Objections to confirmation of the Plan must be filed with Bankruptcy Court by November 12, 2003. The Bankruptcy Court has scheduled the confirmation hearing to determine whether the Plan should be confirmed on November 21, 2003.

because none of the holders of claims or equity interests are impaired under the NRG Northeast and NRG South Central Plan. The Bankruptcy Court has scheduled a hearing on the confirmation of the NRG Northeast and NRG South Central Plan on November 21, 24 and 25, 2003.

Net cash provided by operating activities for the nine months ended September 30, 2003 decreased compared to the same period in 2002. This decrease is primarily due to unfavorable operating results. The decrease due to operating results was offset by improved working capital resulting from reduced accounts receivable balances.

Net cash used by investing activities for the nine months ended September 30, 2003, was favorably impacted as compared to the same period in 2002 due to a reduction in capital expenditures and further enhanced by cash proceeds received upon sale of property during 2003.

Net cash used by financing activities for the nine months ended September 30, 2003 was favorably impacted as compared to the same period in 2002 due to debt principal payments not being made during 2003, offset in part by no borrowings during 2003 and additional deferred financing costs in connection with the DIP financing arrangements.

As of September 30, 2003, the Company does not have any significant relationships with structured finance or special purpose entities that provide liquidity, financing or incremental market risk or credit risk.

The Company has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to its capital expenditure program. The following is a summarized table of contractual obligations. See additional discussion in Item 15 and Notes 6, 7 and 12 to the Consolidated Financial Statements of the Company’s Form 10-K filing for the year ended December 31, 2002.


	Payments Due by Period Subsequent to September 30, 2003

	Total		Short Term		1-3 Years		4-5 Years		After 5 Years

	(In thousands)

Long term debt	$	556,500	$	556,500	$	—	$	—	$	—
Operating leases		6,676		780		1,536		1,048		3,312
Note payable — affiliate	$	30,000	$	30,000		—		—		—

Total contractual cash obligations	$	593,176	$	587,280	$	1,536	$	1,048	$	3,312

The Company provides performance guarantees to third parties on behalf of NRG Power Marketing in relation to certain of its sales and supply agreements.

The tables below disclose the Company’s derivative activities that include non-exchange traded contracts accounted for at fair value. Specifically, these tables disaggregate realized and unrealized changes in fair value; identify changes in fair value attributable to changes in valuation techniques; disaggregate estimated fair values at the three and nine months ended September 30, 2003 based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at the three and nine months ended September 30, 2003.


	Three Months Ended			Nine Months Ended
Gains/(Losses)(In thousands)	September 30, 2003			September 30, 2003

Fair value of contracts outstanding at the beginning of the period	$	2,938		$	(3,641	)
Contracts realized or otherwise settled during the period		6,813			41,209
Fair value of new contract when entered into during the period		—			—
Changes in fair values attributable to changes in valuation techniques		—			—
Other changes in fair values		(10,144	)		(37,961	)

Fair value of contracts outstanding at the end of the period	$	(393	)	$	(393	)


	Fair Value of Contracts at Period End

	Maturity							Maturity in
	Less than 1			Maturity		Maturity		excess of		Total Fair
Maturity schedule (In thousands)........	Year			1-3 Years		4-5 Years		5 Years		Value

Prices actively quoted	$	(393	)	$	—	$	—	$	—	$	(393	)
Prices provided by other external sources		—			—		—		—		—
Prices based on models & other valuation methods		—			—		—		—		—

	$	(393	)	$	—	$	—	$	—	$	(393	)

In January 2003, the FASB issued FASB Interpretation No. 46, “Consolidation of Variable Interest Entities”, (FIN No. 46). FIN No. 46 requires an enterprise’s consolidated financial statements to include subsidiaries in which the enterprise has a controlling interest. Historically, that requirement has been applied to subsidiaries in which an enterprise has a majority voting interest, but in many circumstances the enterprise’s consolidated financial statements do not include the consolidation of variable interest entities with which it has similar relationships, but no majority voting interest. Under FIN No. 46 the voting interest approach is not effective in identifying controlling financial interest. The new rule requires that for entities to be consolidated that those assets be initially recorded at their carrying amounts at the date the requirements of the new rule first apply. If determining carrying amounts as required is impractical, then the assets are to be measured at fair value as of the first date the new rule applies. Any difference between the net amounts of any previously recognized interest in the newly consolidated entity should be recognized as the cumulative effect of an accounting change. FIN No. 46 becomes effective in the first interim or annual period ending after December 15, 2003. FIN No. 46 will be applied as required and is not expected to have a material impact on the Company.

provisions of SFAS 149 relating to SFAS Statement No. 133 Implementation Issues and effective for fiscal quarters beginning prior to June 15, 2003, should continue to be applied in accordance with their respective effective dates. SFAS No. 149 has not had an impact on the Company.

In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity”, (SFAS No. 150). SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability (or an asset in some circumstances). Many of those instruments were previously classified as equity. The provisions of SFAS No. 150 are effective for financial instruments entered into or modified after May 31, 2003, and otherwise are effective at the beginning of the first interim period beginning after June 15, 2003. SFAS No. 150 has not had a material impact on the Company.

The Company is exposed to market risks, including changes in commodity prices and interest rates, and credit risk as disclosed in Management’s Discussion and Analysis in its annual report on Form 10-K for the year ended December 31, 2002. Except as follows, there have been no material changes as of September 30, 2003 to the market risk disclosures presented as of December 31, 2002.

The Company is exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. To manage earnings volatility associated with these commodity price risks, the Company, through its affiliate NRG Power Marketing, may enter into financial instruments, which may take the form of fixed price, floating price or indexed sales or purchases, and options, such as puts, calls, basis transactions and swaps.

Through NRG Power Marketing, the Company utilizes an undiversified “Value-at-Risk” (VAR) model to determine the maximum potential three-day loss in the fair value of the commodity price related financial instruments for the forward twelve months. The VAR for the Company assumes a 95% confidence interval and reflects the Company’s merchant strategy, the generation assets, load obligations and the bilateral physical and financial transactions of the Company. The volatility estimate is based on the implied volatility for at the money daily call options for forward markets where the Company has exposure. This model encompasses the ISO-NE and NYISO generating regions.

The estimated maximum potential three-day loss in fair value of the commodity price related financial instruments, calculated using the VAR model, is approximately $94.0 million and $66.4 million as of September 30, 2003 and 2002, respectively. The average, high and low amounts for the nine months ended September 30, 2003 were $114.4 million, $137.9 million and $94.0 million, respectively. The average, high and low amounts for the nine months ended September 30, 2002 were $53.5 million, $67.5 million and $46.6 million, respectively.

The Chairman, Senior Vice President, General Counsel, Vice President and Treasurer and Vice President and Controller (the Certifying Officers) have evaluated NRG Energy’s disclosure controls and procedures as defined in the rules of the SEC as of the end of the period covered by this report and have determined that, except to the extent indicated otherwise in this paragraph, disclosure controls and procedures were effective in ensuring that material information required to be disclosed by NRG Energy in the reports filed under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. During the fourth quarter of 2002, the Certifying Officers determined that there were certain deficiencies in the internal controls relating to financial reporting at NRG Energy caused by NRG Energy’s pending financial restructuring and business realignment. During the second half of 2002, there were material changes and vacancies in senior NRG Energy management positions and a diversion of NRG Energy financial and management resources to restructuring efforts. These circumstances detracted from NRG Energy’s ability through its internal controls to timely monitor and accurately assess the impact of certain transactions, as would be expected in an effective financial reporting control environment. During 2003 NRG Energy has dedicated significant resources to make corrections to those control deficiencies, including hiring several key senior and middle management positions, hiring an outside consultant to review, document and suggest improvements to controls, and the implementation of new controls and procedures. NRG Energy will continue to dedicate resources to this effort over the next few months. In addition, on October 21, 2003, NRG Energy announced the appointment of David W. Crane as its new President and Chief Executive Officer, effective December 1, 2003. NRG Energy is currently conducting a search for a new Chief Financial Officer and anticipates the position will be filled in the months following its emergence from bankruptcy. Notwithstanding the foregoing and as indicated in the certification accompanying the signature page to this report, the Certifying Officers have certified that, to the best of their knowledge, the financial statements, and other financial information included in this report on Form 10-Q, fairly present in all material respects the financial conditions, results of operations and cash flows of NRG Energy as of, and for the periods presented in this report.

NRG Energy’s Certifying Officers are primarily responsible for the accuracy of the financial information that is represented in this report. To meet their responsibility for financial reporting, they have established internal controls and procedures, which, subject to the disclosure in the foregoing paragraph, they believe, are adequate to provide reasonable assurance that NRG Energy assets are protected from loss. There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of the Certifying Officers evaluation.

For a discussion of material legal proceedings in which the Company was involved through September 30, 2003, see Note 8, “Commitments and Contingencies” to NRG Northeast’s Consolidated Financial Statements and Footnotes contained in Part I, Item 1 of this Form 10-Q.

The Company has identified the following material defaults with respect to the indebtedness of the Company and its significant subsidiaries:

$320 million of 8.065% Series A Senior Secured Bonds due 2004 issued by NRG Northeast Generating LLC

$130 million of 8.824% Series B Senior Secured Bonds due 2015 issued by NRG Northeast Generating LLC

$300 million of 9.29% Series C Senior Secured Bonds due 2024 issued by NRG Northeast Generating LLC

In addition to the foregoing, there may be additional technical defaults with respect to these or other NRG Northeast debt instruments. Defaults on or acceleration of the foregoing debt instruments may result in cross-defaults on or cross-acceleration of these or other NRG Northeast debt instruments. However, the Company made a total of $24.8 million of interest payments due June 15, 2003 on the Series A, B and C Bonds.

The information presented in this quarterly report includes forward-looking statements in addition to historical information. These statements involve known and unknown risks and relate to future events, or projected business results. In some cases forward-looking statements may be identified by their use of such words as “may,” “expects,” “plans,” “anticipates,” “contemplates,” “believes,” and similar terms. Forward-looking statements are only predictions or expectations and actual results may differ materially from the expectations expressed in any forward-looking statement. While the Company believes that the expectations expressed in such forward-looking statements are reasonable, the Company can give no assurances that these expectations will prove to have been correct. In addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements, factors that could cause actual results to differ materially from those contemplated in any forward-looking statements include, among others, the following:

•

NRG Energy’s ability to borrow additional funds and access capital markets;

•

NRG Energy’s substantial indebtedness and the possibility that NRG Energy may incur additional indebtedness going forward;

•

Restrictions on the ability to pay dividends, make distributions or otherwise transfer funds to NRG Energy contained in the debt agreements of certain of NRG Energy’s subsidiaries and project affiliates generally;

•

Volatility of energy and fuel prices and the possibility that NRG Energy will not have sufficient working capital and collateral to post performance guarantees or margin calls to mitigate such risks or manage such volatility;

•

Reduced competition in the power generation industry as regulators in certain markets advocate and allow utilities and utility holding companies to transfer unprofitable generation assets from non-utility entities to regulated utility entities (where costs can be recovered through regulated cost-of-serve rates);

•

Certain of NRG Energy’s pre-petition creditors may receive NRG Energy common stock upon NRG Energy’s emergence from bankruptcy and will have the right to select NRG Energy’s board members and influence certain aspects of NRG Energy’s business operations;

•

The condition of the capital markets generally, which will be effected by interest rates, foreign currency fluctuations and general economic conditions;

•

Changes in the wholesale power market, including reduced liquidity which may limit opportunities to capitalize on short-term price volatility;

•

Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where The Company has a financial interest;

•

Changes in government regulation, including but not limited to pending changes of market rules, market structures, rates, tariffs, environmental regulations, and regulatory compliance requirements imposed by the Federal Energy Regulatory Commission (FERC), state commissions, other state regulatory agencies, the Environmental Protection Agency (EPA), the National Electric Reliability Council (NERC) or other regulatory or industry bodies;

•

Cost and other effects of legal and administrative proceedings, settlements, investigations and claims, including claims which are not discharged in the bankruptcy proceedings and claims arising after the date of the Company’s bankruptcy filing;

•

The impact of the bankruptcy proceedings on NRG Energy’s or the Company’s operations going forward, including the impact on NRG Energy’s ability to negotiate favorable terms with suppliers, customers, landlords and others.

•

Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, or “FASB,” the SEC, the FERC and similar entities with regulatory oversight;

•

Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related or other damage to facilities; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, or gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;

•

Large energy blackouts, such as the blackout that impacted parts of the northeastern United States and Canada during the middle of August 2003, which have the potential to reduce NRG Energy’s revenue collection, increase NRG Energy’s costs and engender enhanced federal and state regulatory requirements;

•

The Company’s inability to enter into intermediate and long-term contracts to sell power and procure fuel on terms and prices acceptable to the Company;

•

Failure of customers and suppliers to perform under agreements, including failure to deliver procured commodities and services and failure to remit payment as required and directed, especially in instances where the Company is relying on single suppliers or single customers at a particular facility;

•

Employee workforce factors including the hiring and retention of key executives, including NRG Energy’s new CEO, collective bargaining agreements with union employees, or work stoppages;

•

Factors associated with various investments including partnership actions, competition, operating risks, dependence on certain suppliers and customers and domestic and foreign environmental and energy regulations;

•

Limitations on the Company’s ability to control projects in which the Company has less than 100% interest;

•

Uncertainties affecting the financial projections prepared in connection with the bankruptcy;

•

Risks associated with timely completion of capital improvement and re-powering projects, including supply interruptions, work stoppages, labor disputes, social unrest, weather interferences, unforeseen engineering, environmental or geological problems and unanticipated cost overruns;

•

Failure to sell certain assets in the amounts and on the timetable assumed, including failure to timely satisfy the closing conditions contained in the definitive agreements for the sale of projects but not yet closed, many of which are beyond NRG Energy’s control;

•

Effects of political, regulatory and legal conditions on our international operations;

•

Other business or investment considerations that may be disclosed from time to time in our SEC filings or in other publicly disseminated written documents.

The Company undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The foregoing review of factors that could cause the Company’s actual results to differ materially from those contemplated in any forward-looking statements included in this Form 10-Q should not be construed as exhaustive.

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.


Delaware		41-1937472
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

901 Marquette Avenue, Suite 2300 Minneapolis, Minnesota		55402
(Address of principal executive offices)		(Zip Code)


Part I — FINANCIAL INFORMATION
	Item I — Consolidated Financial Statements and Notes
		Consolidated Statements of Operations
		Consolidated Balance Sheets
		Consolidated Statements of Members’ Equity
		Consolidated Statements of Cash Flows
		Notes to Consolidated Financial Statements
	Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Item 3. Quantitative and Qualitative Disclosures About Market Risk
	Item 4. Controls and Procedures
Part II — OTHER INFORMATION
	Item 1. Legal Proceedings
	Item 3. Defaults Upon Senior Securities
	Item 6. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
	Cautionary Statement Regarding Forward-Looking Statements
SIGNATURES
EX-31.1 Section 302 Certification
EX-31.2 Section 302 Certification
EX-31.3 Section 302 Certification
EX-32 Section 906 Certification


(In thousands)	September 30, 2003		December 31, 2002

Fuel oil	$	64,609	$	47,052
Spare parts		49,923		59,524
Coal		12,692		14,378
Kerosene		2,623		2,852
Other		328		157

Total	$	130,175	$	123,963


Facilities, machinery and equipment			7 to 30 years
Office furnishings and equipment			3 to 10 years


(In thousands)		September 30, 2003			December 31, 2002

Facilities, machinery and equipment		$	1,153,565		$	1,415,726
Land			46,905			46,925
Construction in progress			17,542			27,615
Office furnishings and equipment			1,195			1,196
Accumulated depreciation			(163,139	)		(157,534	)

	Property, plant and equipment, net	$	1,056,068		$	1,333,928

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x		Quarterly report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934

o		Transition report pursuant to section 13 or 15(d) of the Securities Exchange Act of 1934


For the Quarter Ended: September 30, 2003		Commission File No. 333-42638


			Accretion Nine
	Beginning Balance		Months Ended		Ending Balance
(In thousands)	Jan. 1, 2003		September 30, 2003		September 30, 2003

Somerset Power LLC	$	313	$	32	$	345

Total	$	313	$	32	$	345


	For the nine months ended
	September 30,

(In thousands)	2003		2002

Net cash provided by operating activities	$	446	$	45,546


	Amount of Commitment by Expiration Period as of September 30, 2003

	Total Amounts
	Committed		Short Term		1-3 Years		4-5 Years		After 5 Years

	(In thousands)

Guarantees	$	35,300	$	17,000	$	5,000	$	—	$	13,300

Total guarantees	$	35,300	$	17,000	$	5,000	$	—	$	13,300


				NRG Northeast Generating LLC (Registrant)
				/s/ Scott J. Davido Scott J. Davido, Vice President (Principal Executive Officer)

				/s/ George P. Schaefer George P. Schaefer, Treasurer (Principal Financial Officer)

				/s/ William T. Pieper William T. Pieper, Controller (Principal Accounting Officer)