UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

[X] Quarterly report pursuant to section 13 or 15(d) of the securities exchange act of 1934

[ ] Transition report pursuant to section 13 or 15(d) of the securities exchange act of 1934


For the Quarter Ended: June 30, 2002		Commission File No. 333-42638

NRG Northeast Generating LLC
(Exact name of Registrant as specified in its charter)


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

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

(612) 373-5300
(Registrant’s telephone number, including area code)

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.

Yes X No

The Registrant meets the conditions set forth in General Instruction H (1) (a) and (b) of Form 10-Q and is therefore filing this Form with the reduced disclosure format.

TABLE OF CONTENTS


		CONSOLIDATED STATEMENT OF OPERATIONS
		CONSOLIDATED BALANCE SHEET
		CONSOLIDATED STATEMENT OF MEMBER’S EQUITY
		CONSOLIDATED STATEMENT OF CASH FLOWS
		NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
	ITEM 2 — MANAGEMENTS DISCUSSION AND ANALYSIS
Part II — OTHER INFORMATION
	ITEM 1 — Legal Proceedings
	ITEM 6. Exhibits and Reports on Form 8-K
SIGNATURES

TABLE OF CONTENTS

INDEX


		Page No.
Part I

Item 1	Consolidated Financial Statements and Notes

	Consolidated Statement of Operations	1

	Consolidated Balance Sheet	2

	Consolidated Statement of Member’s Equity	3

	Consolidated Statement of Cash Flows	4

	Notes to Consolidated Financial Statements	5

Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations Results of Operations	9

Item 3	Quantitative and Qualitative Disclosures About Market Risk (Omitted per general instruction H2 (a) and (b) of Form 10-Q)	—

Part II

Item 1	Legal Proceedings	12

Item 6	Exhibits, Financial Statement Schedules, and Reports on Form 8-K	13

	Cautionary Statement Regarding Forward Looking Information	14

SIGNATURES		15

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF OPERATIONS


		Three Months Ended						Six Months Ended
		June 30,						June 30,
		2002			2001			2002			2001

		(Unaudited)			(Unaudited)			(Unaudited)			(Unaudited)

(In thousands)
Operating revenues
	Revenues	$	185,080		$	270,819		$	316,648		$	546,551
Operating costs and expenses
	Operating costs		110,518			221,531			208,553			416,920
	Depreciation		13,840			12,332			26,151			24,315
	General and administrative expenses		7,669			4,927			11,341			9,108

Operating income			53,053			32,029			70,603			96,208
Other income (expense)
	Other income, net		4,811			701			5,034			1,291
	Interest expense		(11,111	)		(15,045	)		(26,744	)		(30,336	)

Net income		$	46,753		$	17,685		$	48,893		$	67,163

See accompanying notes to consolidated financial statements.

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET


				June 30,		December 31,
				2002		2001

				(Unaudited)

(In thousands)
Assets
Current Assets:
	Cash and cash equivalents			$	—	$	370
	Accounts receivable				78,600		56,025
	Inventory				146,321		172,215
	Prepaid expenses				27,755		20,116

			Total current assets		252,676		248,726

Property, plant & equipment, net of accumulated depreciation of $138,780 and $113,688					1,399,862		1,403,318
Deferred finance costs, net of accumulated amortization of $958 and $750					9,198		9,406
Derivative instruments valuation — at market					114,913		109,017
Other assets, net of accumulated amortization of $2,171 and $1,737					23,829		24,263

			Total assets	$	1,800,478	$	1,794,730

Liabilities and Member’s Equity
Liabilities:
	Current portion of long-term debt			$	71,000	$	107,000
	Accounts payable				272		2,550
	Accounts payable — affiliates				32,307		—
	Accrued fuel and purchased power expense				13,015		27,049
	Accrued interest				3,666		2,302
	Bank overdraft				1,464		—
	Other accrued liabilities				41,143		41,086
	Derivative instruments valuation — at market				35,212		32,504

			Total current liabilities		198,079		212,491
Long-term debt					485,500		503,000
Note payable — affiliate					30,000		—
Other long-term liabilities					24,391		24,655

			Total liabilities		737,970		740,146
Commitments and contingencies
Member’s equity					1,062,508		1,054,584

		Total liabilities and member’s equity		$	1,800,478	$	1,794,730

See accompanying notes to consolidated financial statements.

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF MEMBER’S EQUITY
(Unaudited)


							Accumulated
	Member						Other			Total
	Contributions/			Accumulated			Comprehensive			Member’s
	Distributions			Net Income			Income			Equity

				(In thousands)
Balances at December 31, 2000	$	788,315		$	—			—		$	788,315
Net income		—			67,163			—			67,163
Cumulative effect upon adoption of SFAS No. 133		—			—			14,100			14,100
Impact of SFAS No. 133 for the six months ended June 30, 2001		—			—			107,637			107,637

Comprehensive income											188,900
Distributions to member, net		(68,837	)		(67,163	)		—			(136,000	)

Balances at June 30, 2001	$	719,478		$	—		$	121,737		$	841,215

Balances at December 31, 2001	$	788,315		$	158,528			107,741		$	1,054,584
Net income		—			48,893			—			48,893
Impact of SFAS No. 133 for the six months ended June 30, 2002		—			—			(40,969	)		(40,969	)

Comprehensive income											7,924

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

See accompanying notes to consolidated financial statements.

NRG NORTHEAST GENERATING LLC AND SUBSIDIARIES
CONSOLIDATED STATEMENT OF CASH FLOWS


				Six Months Ended
				June 30,
				2002			2001

				(Unaudited)			(Unaudited)

(In thousands)
Cash flows from operating activities:
	Net income			$	48,893		$	67,163
	Adjustments to reconcile net income to net cash provided by (used in) operating activities
		Depreciation			26,151			24,315
		Amortization of other assets			434			433
		Amortization of deferred financing costs			208			208
		Unrealized (loss)/gain on energy contracts			(44,157	)		37,739
		Changes in assets and liabilities:
			Accounts receivable		(22,575	)		89,732
			Inventories		25,894			(53,374	)
			Prepaid expenses		(7,639	)		(11,990	)
			Accounts payable		(2,278	)		(2,000	)
			Accounts payable — affiliates		32,307			54,589
			Accrued interest		1,364			11,824
			Accrued fuel and purchased power expense		(14,034	)		7,189
			Other accrued liabilities		57			(10,560	)
			Other liabilities		(264	)		(322	)

Net cash provided by operating activities					44,361			214,946

Cash flows from investing activities:
	Proceeds from fixed asset dispositions				972			—
	Capital expenditures				(23,667	)		(11,467	)

Net cash used in investing activities					(22,695	)		(11,467	)

Cash flows from financing activities:
	Distribution to member				—			(136,000	)
	Deferred financing costs				—			(198	)
	Proceeds from note payable — affiliate				30,000			—
	Bank overdraft				1,464			—
	Principal payments on long-term debt				(53,500	)		(45,000	)

Net cash used in financing activities					(22,036	)		(181,198	)

Net increase in cash and cash equivalents					(370	)		22,281
Cash and cash equivalents at beginning of period					370			2,444

Cash and cash equivalents at end of period				$	—		$	24,725

See accompanying notes to consolidated financial statements.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NRG Northeast Generating LLC (the Company or NRG Northeast), a wholly-owned indirect subsidiary of NRG Energy, Inc. (NRG), 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 Harbor Power LLC, Oswego Harbor Power LLC and Somerset Power LLC.

Additional information regarding the Company can be found in NRG Energy’s Form 10-K for the year ended December 31, 2001.

The accompanying unaudited consolidated financial statements have been prepared in accordance with the 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 8 — Note 2 to the Company’s financial statements in its annual report on Form 10-K for the year ended December 31, 2001 (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.

In the opinion of management, the accompanying unaudited interim financial statements contain all material adjustments necessary to present fairly the consolidated financial position of the Company as of March 31, 2002 and December 31, 2001, the results of its operations for the three and six months ended June 30, 2002 and 2001, and its cash flows and member’s equity for the six months ended June 30, 2002 and 2001.

Certain prior-year amounts have been reclassified for comparative purposes. These reclassifications had no effect on net income or total member’s equity as previously reported.

1. LONG-TERM DEBT

On February 22, 2000, the Company issued $750 million of senior secured bonds to refinance short-term project borrowings and for certain other purposes. The bond offering included three tranches: $320 million with an interest rate of 8.065% due in 2004; $130 million with an interest rate of 8.842% due in 2015; and $300 million with an interest rate of 9.292% due in 2024. Principal payments are made semi-annually with $107 million due in 2002, $35 million due in 2003, $38 million due in 2004, and no payments due in 2005 and 2006. The remaining $430 million is due between June 15, 2007 and December 15, 2024. The bonds are jointly and severally guaranteed by each of NRG Northeast’s existing and future subsidiaries. The bonds are secured by a security interest in NRG Northeast’s membership or other ownership interests in the guarantors and its rights under all intercompany notes between NRG Northeast and the guarantors. At June 30, 2002, there remain $556.5 million of outstanding bonds.

On August 7, 2002, NRG Energy, Inc. senior unsecured debt was downgraded by Standard & Poor’s Rating Services to B-plus. As a consequence, NRG is required under the Indenture to replace the corporate guarantee supporting the six month debt service reserve account with a letter of credit or cash collateral by August 25, 2002 to avoid an event of default. If NRG Fails to meet this collateral requirement by August 25, 2002, NRG will have 30 days to either cure the default or actively work to cure the default, after which the bondholders will have the right to accelerate the bonds. If 60 days after August 25, 2002 NRG still has not collateralized the debt service reserve the account, the bondholders will have the right to accelerate the bonds.

On August 8, 2002, NRG met with several banks and committed not to collateralize any debt service reserve accounts, including NRG Northeast Generating, without the prior consent of NRG's lenders. At this time NRG management believes that its lenders will ultimately consent to the provision of collateral for NRG Northeast Generating in advance of any potential acceleration of the bonds.

Due to the debt rating downgrade, NRG is no longer eligible to guarantee the Company’s senior secured bonds. The indenture for the senior secured bonds requires, as a result, that the Company fund the next six months’ debt service requirements of $78.2 million. The Company and the lenders are in discussion, but if this requirement is not waived or deferred, and the Company cannot fund the debt service requirement, the Company will be in default and the lenders can exercise their rights under the indenture agreement.

On June 15, 2002, NRG loaned the Company $30 million to fund capital expenditures. The debt bears interest at the 3 month London Interbank Offered Rate plus 0.5%. The debt is subordinate to the other long-term debt of the Company and is subject to the terms and conditions of the senior secured bonds’ indenture.

2 — Inventory

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

Inventory consisted of:


(In thousands)		June 30, 2002		December 31, 2001

Fuel oil		$	64,148	$	83,857
Spare parts			59,490		57,901
Coal			22,062		29,179
Kerosene			609		1,268
Other			12		10

	Total	$	146,321	$	172,215

3 — Property, Plant and Equipment, net

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


Facilities, machinery and equipment		25 to 30 years
Office furnishings and equipment		3 to 10 years

Property, plant and equipment consisted of:


(In thousands)		June 30, 2002			December 31, 2001

Facilities, machinery and equipment		$	1,447,613		$	1,441,428
Land			51,920			51,920
Construction in progress			37,650			22,206
Office furnishings and equipment			1,459			1,452
Accumulated depreciation			(138,780	)		(113,688	)

	Property, Plant and Equipment, net	$	1,399,862		$	1,403,318

4. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITY

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 June 30, 2002, the Company had derivative contracts extending through December 2006.

Accumulated Other Comprehensive Income

The following table summarizes the effects of SFAS No. 133 on the Company’s Other Comprehensive Income balance as of June 30, 2002:


		Three Months Ended						Six Months Ended
Gains/(Losses)		June 30,						June 30,
(In thousands)		2002			2001			2002			2001

Beginning Balance
	Unwound from OCI during period:	$	87,871		$	92,386		$	107,741		$	—
	- due to unwinding of previously deferred amounts		(79	)		(11,300	)		(3,925	)		(6,100	)
	Mark to market to hedge contracts		(21,020	)		40,651			(37,044	)		127,837

Ending Balance		$	66,772		$	121,737		$	66,772		$	127,837

Gains/(Losses) expected to unwind from OCI during next 12 months		$	30,041					$	30,041		$	—

During the three and six months ended June 30, 2002, the Company recorded a loss in OCI of approximately $21.1 million and $41.0 million, respectively, 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 June 30, 2002 was a gain of approximately $66.8 million. The Company expects $30.0 million of the deferred net gains on derivative instruments accumulated in OCI to be recognized as earnings during the next twelve months.

Statement of Operations

The following tables summarize the effects of SFAS No. 133 on the Company’s statement of operations for the three month and six month periods ended June 30, 2002 (prior year information regarding the breakout between revenue and operating costs was not available. As such, all activity is shown as revenue in 2001):


		Three Months Ended					Six Months Ended
Gains/(Losses)		June 30,					June 30,

(In thousands)		2002		2001			2002		2001

Revenues		$	30,643	$	(38,900	)	$	34,573	$	(37,700	)
Operating costs			3,530					9,584

	Total statement of operations impact	$	34,173	$	(38,900	)	$	44,157	$	(37,700	)

During the three and six months ended June 30, 2002 and 2001, the Company recognized no gain or loss due to ineffectiveness of commodity cash flow hedges.

The Company’s earnings for the three months ended June 30, 2002 and 2001 were increased by an unrealized gain of $34.2 million and decreased by an unrealized loss of $38.9 million, respectively. For the six months ended June 30, 2002 and 2001 the Company’s earnings were increased by an unrealized gain of $44.2 million and decreased by an unrealized loss of $37.7 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.

5. REGULATORY ISSUES

New England

On April 26, 2001 the Federal Energy Regulatory Commission (FERC) approved with a July 2001 implementation date, a change in the energy market bidding structure in New England from a one part bidding structure with hourly uplift compensation to a three part bidding system with Net Commitment Period Compensation (NCPC). Under this three part bidding system, a supplier submits separate bids for energy, start up costs and no load. Also under this revised bidding structure, a supplier is guaranteed of receiving an amount at least equal to the combination of its start up, no load and accepted energy bids over the course of the day when it is dispatched to run in the energy market. The impact of this change is that payments for operations dispatched out-of-merit, or from operations required to relieve transmission congestion are evaluated over a twenty-four hour period and compensation is paid if the monies received from the energy market are insufficient to cover the as-bid offer. Previously, payments for out-of-merit energy was awarded on an hourly basis and therefore payments received for out-of-merit energy under three part bidding with NCPC are expected to be lower than under previously single part bid market.

On August 28, 2001, the FERC ruled that a capacity deficiency of $4.87 per KW per month was appropriate. The deficiency charge acts as a price cap for the Installed Capacity (ICAP) market because load-serving entities (LSE) that do not satisfy their ICAP purchase obligation must pay the deficiency charge. Previous to this ruling, a temporary deficiency charge of $0.17 per KW per month existed. In the same order, the FERC rejected ISO-NE’s proposed after-the-fact cure period for LSE’s ICAP purchase obligation.

Effective May 1, 2002 certain rule changes went into effect which reflect in part the recommendations made by ISO-NE’s market advisor, David Patton. Rule changes that are intended to improve the efficiency of the price signal for energy during high load periods include amending eligibility requirements for resources eligible to set the clearing prices, changes to reserve markets including the inclusion of Replacement Reserves in the Thirty Minute Operating Reserve Markets and rules on transaction across the tie lines to New York.

New York

On October 31, 2001, the extension of the New York City mitigation measures to the real time market and out-of-merit dispatches expired. Consolidated Edison Company of New York (ConEd) has requested an extension of the expanded mitigation measures. On November 27, 2001, the FERC denied this request and directed the NYISO to address the concerns of ConEd in a comprehensive mitigation filing, which is referenced below. On March 20, 2002, the NYISO filed its comprehensive mitigation proposal with the FERC. Under the proposal, the Day-Ahead energy market (DAM) bids of New York City suppliers would continue to be mitigated under the existing ConEd mitigation rules with the following changes. Specifically, the DAM bid for each hour, would be compared to the energy price at the Indian Point 2 bus and if the In-City bid exceeded the Indian Point 2 price by more than 107%, all of the DAM energy bids of the supplier would be mitigated to a reference price. The reference price represents either an average of accepted energy bids in the DAM over the last thirty days or a level negotiated with the NYISO. Regarding the real-time energy market (RTM), the NYISO proposal for New York City restricts the ability of a facility to bid above its reference price according to the level of congestion In-City. If congestion prohibits energy from being imported into the City and is also present within the New York City loads pockets, the NYISO proposal would restrict the ability to bid above the reference price by approximately two percent. If there is no congestion found in New York City, the facilities can bid approximately one hundred dollars above its referenced price. Currently, the New York City mitigation measures only apply in the day-ahead market. The effect of the expiration of part of these mitigation measures means that in the real time market and out-of-merit dispatches, the Company’s generating assets in New York City are subject only to the NYISO’s New York state mitigation measures.

On April 30 2002, the automatic mitigation measure for the entire New York State DAM expired. On May 1, 2002, the FERC approved a NYISO request for extension of the automatic mitigation procedures until May 31, 2002. The extension was granted to permit the FERC to consider the NYISO’s comprehensive mitigation proposal noted above. The automatic mitigation measures evaluate a suppliers’ bids to determine if (1) the bid exceeds the suppliers’ historically accepted bids (over the past 90 days) by more than $100 and (2) that there is an impact on the state-wide or a portion of the state’s energy price by more than $100. If both of these occur, the supplier’s energy bid is reduced to the facility’s historically accepted bids. The impact of the expiration of the automatic mitigation measures means that the Company and other market participants have greater flexibility in submitting bids in the DAM.

The New York energy markets are subject to a price cap of $1,000 per Megawatt Hour (MWh). This cap will continue indefinitely.

On September 4, 2001, the FERC approved the request of the NYISO to revise the ICAP market to one based on unforced capacity similar to the capacity market in the Pennsylvania New Jersey Maryland Interconnection. The change from a capacity market that is based on ICAP to one based on unforced capacity requires that certain New York City Capacity requirements be revised to reflect the change. Under ICAP methodology, ICAP sold by the Company and other New York City generators was capped at $105 per Kilowatt (KW) year. In the September 4th order, the FERC increased the price cap to approximately $112 per KW year. Also in the order the FERC reduced the amount of In-City Capacity an LSE must purchase by 8.6%. The amount of New York City capacity that can be sold as unforced capacity is dependent on the availability of the generating assets to NYISO dispatch instructions. Initially, the FERC reduced the amount of capacity available from New York City generation by approximately 7.1%. The effect of these changes is that the capacity price cap is higher while the amount of capacity an LSE must purchase from New York City generation and the amount of available New York City generating capacity is reduced.

6. COMMITMENTS AND CONTINGENCIES

Contractual Commitments

During 1999, the Company acquired the Huntley and Dunkirk generating facilities from Niagara Mohawk Power Corp. (NiMo). In connection with this acquisition, the Company entered into a four-year agreement with NiMo that requires the Company to provide to NiMo pursuant to a predetermined schedule fixed quantities of energy and capacity at a fixed price.

During 1999, the Company acquired certain generating facilities from Connecticut Light and Power Corp (CL&P). The Company also entered into a four-year standard offer agreement that requires the Company to provide to CL&P a portion of its load requirements through the year 2003 at a substantially fixed rate.

During 1999, the Company acquired the Oswego generating facilities from NiMo and entered into a 4-year transition power sales contract with NiMo in order to hedge NiMo’s transition to market rates. Under the agreement, NiMo will pay to Oswego Power a fixed monthly price plus start up fees for the right to claim, at a specified delivery point(s), the installed capacity of unit 5 and for the right to exercise an option for an additional 350 MW of installed capacity.

NRG Power Marketing has entered into a wholesale standard offer service agreement with Blackstone Valley Electric Company, Eastern Edison Company and Newport Electric Corporation (collectively the EUA Companies). Under the agreement, NRG Power Marketing is obligated to provide each of the EUA Companies with firm all-requirements electric service, including capacity, energy, reserves, line losses and related services necessary to serve the aggregate load attributable to retail customers taking standard offer service. The price the EUA Companies pay to NRG Power Marketing for each unit of electricity is a fixed price plus a fuel cost adjustment factor.

ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS

Management’s Discussion and Analysis of Financial Condition is omitted per conditions as set forth in General Instructions H (1) (a) and (b) of Form 10-Q for wholly owned subsidiaries. It is replaced with management’s narrative analysis of the results of operations as permitted by General Instructions H (2) (a) of Form 10-Q for wholly owned subsidiaries (reduced disclosure format). This analysis will primarily compare the Company’s revenue and expense items for the three and six months ended June 30, 2002 with the three and six months ended June 30, 2001.

RESULTS OF OPERATIONS

Net income for the three and six months ended June 30, 2002 was $46.8 million and $48.9 million, an increase of $29.1 million and a decrease of $18.3 million, respectively, compared to the same periods in 2001. These changes represent an increase of 164% and a decrease of 27.2%, respectively. These changes were due to the following factors described below.

Operating Revenues

For the three months ended June 30, 2002, the Company had total revenues of $185.1 million, compared to $270.8 million for the same period in 2001, a decrease of $85.7 million or 31.6%. The decrease in revenues for the three months ended June 30, 2002 versus the same period in 2001 is due to a combination of lower capacity revenues realized of approximately $8.7 million and a 26% decline in megawatt hour generation compared with the same period in 2001. This decline in generation is attributable to cooler temperatures in the first two months of the quarter and new regulatory rules that reduced price volatility and thus unit dispatch opportunities.

For the six months ended June 30, 2002, the Company had total revenues of $316.6 million, compared to $546.6 million for the same period in 2001, a decrease of $230.0 million or 42.1%. The decrease in revenues for the six months ended June 30, 2002 versus the same period in 2001 is due to a combination of lower capacity revenues realized of approximately $40.7 million and a 32% decline in megawatt hour generation compared with the same period in 2001. This decline in generation is attributable to an unseasonably warm winter and cooler spring together with new regulatory rules which reduced price volatility, particularly in New York City, where the Company’s plants sell into the merchant energy market.

Cost of Operations

Operating costs were $110.5 million for the three months ended June 30, 2002 compared to $221.5 million for the same period in 2001, a decrease of $111.0 million, or 50.1%. Operating costs, as a percentage of operating revenues, were 59.7% for the three months ended June 30, 2002 compared to 81.8% for the same period in 2001. For the six months ended June 30, 2002, operating costs were $208.6 million compared to $416.9 million for the same period in 2001, a decrease of $208.4 million or 50.0%. Operating costs, as a percentage of operating revenues were 65.9% for the six months ended June 30, 2002 compared to 76.3% for the same period in 2001. Operating costs primarily consist of expenses for fuel, plant operations and maintenance and unrealized gains or losses associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133. The decrease in operating costs is primarily due to a reduction in fuel cost due to a decline in power generation, a general decline in the price of fuel, lower expenditures on plant maintenance and operations and a $9.6 million favorable swing in unrealized gains or losses associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

Fuel expense for the three months ended June 30, 2002 was $59.5 million compared to $156.3 million for the same period in 2001, a decrease of $96.8 million or 61.9%. Fuel expense for the three months ended June 30, 2002 represented 32.2% of revenues compared to 57.7% for the same period in, 2001. Fuel expense included $25.1 million of coal, $26.3 million of natural gas, $11.6 million of fuel oil, diesel and other related costs, partially offset by $3.5 million of unrealized gains on energy contracts for the three months ended June 30, 2002. For the three months ended June 30, 2001, fuel expense included $28.4 million of coal, $51.9 million of natural gas, $37.1 million of fuel oil, diesel and other related costs, and $38.9 million of unrealized losses on energy contracts for the three months ended June 30, 2001. Fuel expense for the six months ended June 30, 2002 was $105.4 million compared to $294.6 million for same period in 2001, a decrease of $189.2 or 64.2%. Fuel expense for the six months ended June 30, 2002 represented 33.3% of revenues compared to 53.9% for the six months ended June 30, 2001. Fuel expense included $48.0 million of coal, $41.1 million of natural gas, $25.9 million of fuel oil, diesel and other related costs, partially offset by $9.6 million of unrealized gains on energy contracts for the three months ended June 30, 2002. For the six months ended June 30, 2001, fuel expense included $64.8 million of coal $73.9 million of natural gas, $118.2 million of fuel oil, diesel and other related costs and $37.7 million of unrealized losses on energy contracts for the six months ended June 30, 2001.

Plant operations and maintenance expense for the three months ended June 30, 2002 was $51.0 million compared to $65.2 million for the same period in 2001, a decrease of $14.2 million or 21.8%. Plant operations and maintenance expense for the three months ended June 30, 2002 represented 27.5% of revenue, and included labor and benefits under operating service agreements of $14.6 million, maintenance parts, supplies and services of $21.0 million and property taxes and other expense of $15.4 million. Plant operations and maintenance expense for the three months ended June 30, 2001 represented 24.1% of revenue, and included labor and benefits under operating service agreements of $17.6 million, maintenance parts, supplies and services of $29.9 million and property taxes and other expenses of $17.7 million. Plant operations and maintenance expense for the six months ended June 30, 2002 was 103.1 million compared to 122.3 million for the same period in 2001, a decrease of $19.2 million or 15.7%. Plant operations and maintenance expense for the six months ended June 30, 2002 represented 32.6% of revenue, and included labor and benefits under operating service agreements of $32.6 million, maintenance parts, supplies and services of $40.3 million and property taxes and other expenses of $30.2 million. Plant operations and maintenance expense for the six months ended June 30, 2001 represented 22.4% of revenue, and included labor and benefits under operating service agreements of $35.7 million, maintenance parts, supplies and services of $51.5 million and property taxes and other expenses of $35.1 million.

Depreciation

Depreciation costs were $13.8 million for the three months ended June 30, 2002, which is an increase of $1.5 million, or 12.2% from the same period in 2001. Depreciations costs were $26.2 million for the six months ended June 30, 2002, which is an increase of $1.9 million, or 7.8% from the same period in 2001. Depreciation expense was primarily related to the acquisition costs of the facilities, which are being depreciated over twenty-five to thirty years. The increase in depreciation expense is attributable to additional depreciation on completed capital projects.

General and Administrative Expenses

General and administrative expenses were $7.7 million for the three months ended June 30, 2002, compared to $4.9 million for the same period in 2001, an increase of $2.8 million or 57.1%. General and administrative expenses were $11.3 million for the six months ended June 30, 2002, compared to $9.1 million for the same period in 2001, an increase of $2.2 million or 24.5%. General and administrative expenses include costs for outside legal and other contract services, payments to NRG Energy for corporate services, expenses related to office administration, as well as costs for certain employee benefits incurred under operating service agreements.

Interest Expense

Interest expense for the three months ended June 30, 2002 was $11.1 million compared to $15.0 million for the three months ended June 30, 2001, a decrease of $3.9 million or 26.0%. Interest expense for the six months ended June 30, 2002 was $26.7 million compared to $30.3 million for the same period in 2001. Interest expense relates to the amortization of deferred finance costs and interest on the senior secured bonds issued on February 22, 2000. The decrease in interest expense is attributable to a decline in the average principle amounts outstanding on the senior secured indebtedness.

Other Income

Other income for the three months ended June 30, 2002 was $4.8 million compared to $0.7 million for the same period in 2001, an

increase of $4.1 million or 585.7%. Other income for the six months ended June 30, 2002 was $5.0 million compared to $1.3 million for the same period in 2001, an increase of $3.7 million or 284.6%. The increase in other income is primarily attributable to receipt of an insurance settlement for $1.5 million and a refund of transfer tax of $2.9 million related to the acquisition of the Company’s Connecticut assets.

Capital Resources

On July 26, 2002, Standard & Poor’s Rating Services announced it had lowered NRG’s corporate credit rating to BB. The secured NRG Northeast Generating LLC bonds were lowered to BB. The senior unsecured bonds of NRG were lowered to B-plus. All of the NRG debt issues and the corporate credit rating were placed on “credit watch” with negative implications. Standard & Poor’s ratings are not a recommendation to buy, sell or hold securities, and each rating should be evaluated independently of any other rating.

On July 29, 2002, Moody’s Investor Service lowered the senior unsecured debt rating of NRG from Baa3 to B1 and assigned a Senior Implied rating of Ba3 to NRG. NRG subsidiaries, including NRG Northeast Generating, NRG South Central Generating LLC and LSP Energy Limited Partnership, were placed under review for possible downgrade. Moody’s ratings are not a recommendation to buy, sell or hold securities, and each rating should be evaluated independently of any other rating.

Contract Negotiation

In July 2002, NRG reached a tentative agreement with Connecticut Light & Power (CL&P) that would result in increased compensation to NRG, a supplier of CL&P’s wholesale supply agreement. CL&P filed an emergency petition with the Connecticut Department of Public Utility Control (DPUC) asking for approval of a shift of wholesale supply agreement revenues, effective August 1, 2002, through December 31, 2003, that would reallocate 0.7 cents per kilowatt-hour in the wholesale price paid to existing suppliers. On July 26, 2002, the DPUC denied the request of CL&P for an emergency letter ruling. On August 9, 2002, NRG Energy announced that it had reached an agreement with ISO-New England to keep three units at its Dover station in service. The agreement expires on September 30, 2003.

New Accounting Pronouncements

In June 2001, the Financial Accounting Standards Board (the FASB) issued Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets (SFAS No. 142). SFAS No. 142 requires that goodwill and intangible assets with indefinite useful lives no longer be amortized but instead be tested for impairment in accordance with SFAS No. 121, Accounting for the Impairment of Long-lived Assets and for Long-lived Assets to Be Disposed Of (SFAS No. 121). Goodwill will no longer be amortized to comply with the provisions of SFAS No. 142. Instead, goodwill and intangible assets that will not be amortized should be tested for impairment annually and on an interim basis if an event occurs or a circumstance changes between annual tests that may reduce the fair value of a reporting unit below its carrying value. An impairment test is required to be performed within six months of the date of adoption, and the first annual impairment test must be performed in the year the statement is initially adopted. NRG Northeast Generating LLC and its subsidiaries have adopted the provisions of SFAS No. 142 effective January 1, 2002. No impairments on assets were recorded upon adopting SFAS 142 on January 1, 2002.

In June 2001, FASB issued SFAS No. 143, Accounting for Asset Retirement Obligations (SFAS No. 143). This statement addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. 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. SFAS No. 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. NRG Northeast has not completed its analysis of SFAS No. 143.

In October 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (SFAS No. 144). This statement addresses financial accounting and reporting for the impairment or disposal of long-lived assets. SFAS No. 144 retains and expands upon the fundamental provisions of existing guidance related to the recognition and measurement of the impairment of long-lived assets to be held and used and the measurement of long-lived assets to be disposed of by sale. Generally, the provisions of SFAS No. 144 are effective for financial statements issued for fiscal years beginning after December 15, 2001. NRG Northeast Generating LLC and its subsidiaries have adopted SFAS No. 144 effective January 1, 2002. No impairments were

recognized as a result of adopting SFAS No. 144 on January 1, 2002.

In April 2002, FASB issued SFAS No. 145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical Corrections (SFAS No. 144), that supercedes 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 for prior periods required. In addition, SFAS No. 145 amends SFAS No. 13, Accounting for Leases (SFAS No. 13), 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, 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 are effective for transaction 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.

Critical Accounting Policies and Estimates

The Company 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 (GAAP) 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 8 Note 2 of the consolidated financial statements of NRG Northeast Generating LLC Form 10-K for the year ended December 31, 2001 for additional discussion regarding the Company’s critical accounting policies and estimates.

Part II — OTHER INFORMATION

ITEM 1 — Legal Proceedings

Fortistar Capital V. NRG Energy

In July 1999, Fortistar Capital Inc., a Delaware corporation, filed a complaint in District Court (Fourth Judicial District, Hennepin County) in Minnesota against NRG asserting claims for injunctive relief and for damages as a result of NRG’s alleged breach of a confidentiality letter agreement with Fortistar relating to the Oswego facility in New York. NRG disputed Fortistar’s allegations and asserted numerous counterclaims, and, in October 1999, NRG, through a wholly-owned subsidiary, closed on the acquisition of the Oswego facility. In April and December 2000, NRG had summary judgment motions to dispose of the litigation. A hearing on these motions was held in February 2001 and certain of Fortistar’s claims were dismissed. On May 8, 2002 the parties resolved the litigation, pending final agreement on the terms of settlement. The settlement also encompasses litigation between the parties with respect to Minnesota Methane LLC. NRG Northeast has no obligations pursuant to this Settlement Agreement.

New York Clean Air Act Enforcement Action

In January 2002 the New York Attorney General and the New York Department of Environmental Conservation (NYDEC) filed suit in the western district of New York against NRG and Niagara Mohawk Power Corp. (NiMo), the prior owner of the Huntley and Dunkirk facilities in New York. The lawsuit relates to physical changes made at those facilities prior to NRG’s assumption of ownership. The complaint alleges that these changes represent major modifications undertaken without the required permits having been obtained. Although NRG has a right to indemnification by the previous owner for fines, penalties, assessments and related losses resulting from the previous owner’s failure to comply with environmental laws and regulations, NRG could be enjoined from operating the facilities if the facilities are found not to comply with applicable permit requirements. NRG has filed a motion to dismiss the claims against it.

NYDEC Opacity Notice of Violation

NRG became part of an opacity consent order negotiation as a result of acquiring its Huntley, Dunkirk and Oswego plants from Niagara Mohawk. At the time of financial close on these assets, a consent order was being negotiated between Niagara Mohawk and the NYDEC; it required Niagara Mohawk to pay a stipulated penalty for each opacity event at these facilities. On January 14, 2002, the NYDEC issued NRG Notices of Violations (NOV) for opacity events, which had occurred since the time NRG assumed ownership of the Huntley, Dunkirk and Oswego generating stations. The NOVs allege that a total of 7,231 events had occurred where the average opacity during a six-minute block of time had exceeded 20%. The NYDEC proposed a penalty associated with the NOVs at $900,000.

Station Use Power

On September 21, 2000, Dunkirk, Huntley and Oswego Harbor Power LLC (Oswego) filed an action before the FERC seeking its declaration that they are entitled to pay NiMo wholesale prices for the power consumed at their respective generating facilities, rather than paying for such station power at retail rates, as NiMo alleges is required. On September 28, 2000, NiMo filed separate actions against Dunkirk, Huntley and Oswego in the State Supreme Court of New York, seeking, in total, payment of approximately $7.0 million, which NiMo asserts is due under such retail tariff. NiMo asserts that the amount now owed it exceeds $20 million. The FERC rendered a decision on March 14, 2001, determining that certain types of station use power are not subject to retail tariffs and granting some relief sought by Dunkirk, Huntley and Oswego. Legal counsel is evaluating the impact of the ruling on the merits of the NiMo litigation. The parties in the state court actions have exchanged written discovery and are engaged in depositions. A tentative trial date has been set for September 2002.

Constellation Power Source Inc. Agreement

On August 2, 2002, the Company received payment under a net settlement agreement, of approximately $20 million from Constellation Power Source, Inc., through their affiliate, NRG Power Marketing, Inc. The agreement provides for the termination of a long-term power purchase contract dated February 25, 2002 between Constellation and NRG Power Marketing on the Company’s behalf.

ITEM 6. Exhibits and Reports on Form 8-K


(A)		Exhibits

		None

(B)		Reports on Form 8-K

		July 25, 2002 re: credit rating downgrade

Cautionary Statement Regarding Forward-Looking Statements

The information presented in this Form 10-Q 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,” “believes,” and similar terms. Forward-looking statements are only predications, 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, we 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 reach agreements with its lenders and creditors to restructure debt and delay the funding of collateral required following NRG Energy’s, and the Company’s, ratings downgrades;

	•		The implementation of the business plan Xcel Energy put in place for NRG Energy following completion of the Xcel Energy exchange offer transaction;

	•		NRG Energy’s ability to sell assets in the amounts and on the time table assumed;

	•		General economic conditions including inflation rates and monetary exchange rate fluctuations;

	•		Trade, monetary, fiscal, taxation, and environmental policies of governments, agencies and similar organizations in geographic areas where we have a financial interest;

	•		Customer business conditions including demand for their products or services and supply of labor and materials used in creating their products and services;

	•		Financial or regulatory accounting principles or policies imposed by the Financial Accounting Standards Board, the Securities and Exchange Commission, the Federal Energy Regulatory Commission and similar entities with regulatory oversight;

	•		Factors affecting the availability or cost of capital such as changes in: interest rates; market perceptions of the power generation industry, the Companies or changes in credit ratings;

	•		Factors affecting power generation operations such as unusual weather conditions; catastrophic weather-related damage; 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;

	•		Employee workforce factors including loss or retirement of key executives, collective bargaining agreements with union employees, or work stoppages;

	•		Volatility of energy prices in a deregulated market environment:

	•		Increased competition in the power generation industry;

	•		Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;

	•		Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;

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

	•		Other business or investment considerations that may be disclosed from time to time in our Securities and Exchange Commission filings or in other publicly disseminated written documents including NRG Northeast's Registration Statement No. 333-42638, as amended.

NRG Northeast 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 NRG Northeast’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.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		NRG Northeast Generating LLC (Registrant)



		/s/ RICHARD C. KELLY Richard C. Kelly, President



		/s/ C. ADAM CARTE C. Adam Carte, Treasurer (Principal Financial Officer)

Date: August 14, 2002

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Each of the undersigned hereby certifies, in his/her capacity as an officer of NRG Northeast Generating LLC (the “Company”), for purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

	•		the Quarterly Report of the Company on Form 10-Q for the period ended June 30, 2002 fully complies with the requirements of Section 13(a) of the Securities Exchange Act of 1934; and

	•		the information contained in such report fairly presents, in all material respects, the financial condition and results of operation of the Company.

Dated: August 14, 2002


	/s/ RICHARD C. KELLY
	Richard C. Kelly, President

	/s/ C. ADAM CARTE
	C. Adam Carte, Treasurer

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NRG NORTHEAST GENERATING LLC 10-Q