NRG Energy (NRG) 10-Q 2004 Q1 Quarterly report

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

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

For the Quarter Ended: March 31, 2004 Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of Registrant as specified in its charter)

Delaware
(State or other jurisdiction
of incorporation or organization) 41-1724239
(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)

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

Yesx Noo

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

Yesx Noo

     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.

Yesx Noo

     As of May 10, 2004, there were 100,004,612 shares of common stock outstanding.

TABLE OF CONTENTS

Index

	Page No.
Part I — FINANCIAL INFORMATION
Item 1 Consolidated Financial Statements and Notes
Consolidated Statements of Operations		3
Consolidated Balance Sheets		4
Consolidated Statements of Stockholders’ Equity (Deficit)		6
Consolidated Statements of Cash Flows		7
Notes to Consolidated Financial Statements		8
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
Item 3 Quantitative and Qualitative Disclosures About Market Risk		45
Item 4 Controls and Procedures		47
Part II — OTHER INFORMATION
Item 1 Legal Proceedings		48
Item 3 Defaults Upon Senior Securities		48
Item 6 Exhibits and Reports on Form 8-K		48
Cautionary Statement Regarding Forward Looking Information		49
SIGNATURES		52
Letter Agreement - Scott J. Davido
Letter Agreement - Ershel C. Redd Jr.
Letter Agreement - John P. Brewster
Letter Agreement - Timothy W. O'Brien
Letter Agreement - Robert C. Flexon
Certification of Chief Executive Officer
Certification of Chief Financial Officer
Certifications Pursuant to Section 906

2

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

				Predecessor
	Reorganized NRG			Company
	March 31,			March 31,
	2004			2003
	(In thousands)
Operating Revenues
Revenues from majority-owned operations	$	621,167		$	519,582
Operating Costs and Expenses
Cost of majority-owned operations		392,403			388,097
Depreciation and amortization		58,637			64,071
General, administrative and development		37,339			48,982
Corporate relocation charges		1,116			—
Reorganization charges		6,250			—
Restructuring and impairment charges		—			22,136
Total operating costs and expenses		495,745			523,286
Operating Income/(Loss)		125,422			(3,704	)
Other Income (Expense)
Minority interest in (earnings)/losses of consolidated subsidiaries		(278	)		184
Equity in earnings of unconsolidated affiliates		17,713			45,629
Write downs and losses on sales of equity method investments		(1,738	)		(16,591	)
Other income, net		3,115			9,255
Interest expense		(102,182	)		(176,077	)
Total other expense		(83,370	)		(137,600	)
Income/(Loss) From Continuing Operations Before Income Taxes		42,052			(141,304	)
Income Tax Expense		14,208			32,878
Income/(Loss) From Continuing Operations		27,844			(174,182	)
Income on Discontinued Operations, net of Income Taxes		2,391			161,550
Net Income/(Loss)	$	30,235		$	(12,632	)
Weighted Average Number of Common Shares Outstanding — Basic		100,018
Income From Continuing Operations per Weighted Average Common Share — Basic	$	0.28
Income From Discontinued Operations per Weighted Average Common Share — Basic		0.02
Net Income per Weighted Average Common Share — Basic	$	0.30
Weighted Average Number of Common Shares Outstanding — Diluted		100,018
Income From Continuing Operations per Weighted Average Common Share — Diluted	$	0.28
Income From Discontinued Operations per Weighted Average Common Share — Diluted		0.02
Net Income per Weighted Average Common Shares — Diluted	$	0.30

See notes to consolidated financial statements.

3

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (REORGANIZED COMPANY)

(Unaudited)

	March 31,			December 31,
	2004			2003
	(In thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	832,526		$	552,175
Restricted cash		174,967			157,175
Accounts receivable — trade, less allowance for doubtful accounts of $191 and $0		243,183			212,314
Xcel Energy settlement receivable		352,000			640,000
Current portion of notes receivable — affiliates		1,700			200
Current portion of notes receivable		123,666			65,141
Inventory		182,716			202,323
Derivative instruments valuation		798			772
Prepayments and other current assets		202,806			229,494
Current deferred income taxes		1,028			1,850
Current assets — discontinued operations		48,775			52,395
Total current assets		2,164,165			2,113,839
Property, Plant and Equipment
In service		4,284,466			4,196,714
Under construction		105,810			149,835
Total property, plant and equipment		4,390,276			4,346,549
Less accumulated depreciation		(71,215	)		(12,555	)
Net property, plant and equipment		4,319,061			4,333,994
Other Assets
Equity investments in affiliates		723,324			745,636
Notes receivable, less current portion — affiliates		122,940			130,152
Notes receivable, less current portion		621,968			691,444
Intangible assets, net of accumulated amortization of $22,068 and $5,230		413,085			434,402
Debt issuance costs, net of accumulated amortization of $2,518 and $454		64,194			74,337
Derivative instruments valuation		55,763			59,907
Funded letter of credit		250,000			250,000
Other assets		129,643			133,377
Non-current assets — discontinued operations		277,075			277,899
Total other assets		2,657,992			2,797,154
Total Assets	$	9,141,218		$	9,244,987

See notes to consolidated financial statements.

4

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (REORGANIZED COMPANY)
(Unaudited)

	March 31,			December 31,
	2004			2003
	(In thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt	$	597,726		$	846,551
Short-term debt		19,002			19,019
Accounts payable — trade		175,058			178,387
Accounts payable — affiliate		10,559			10,118
Accrued income tax		14,410			16,095
Accrued property, sales and other taxes		17,937			24,284
Accrued salaries, benefits and related costs		30,238			19,331
Accrued interest		55,245			19,872
Derivative instruments valuation		15,930			429
Creditor pool obligation		377,000			540,000
Other bankruptcy settlement		219,517			220,000
Other current liabilities		104,281			105,734
Current liabilities — discontinued operations		23,793			26,361
Total current liabilities		1,660,696			2,026,181
Other Liabilities
Long-term debt		3,851,670			3,617,881
Deferred income taxes		152,001			149,493
Postretirement and other benefit obligations		108,644			106,537
Derivative instruments valuation		178,255			153,503
Other long-term obligations		503,617			510,102
Non-current liabilities — discontinued operations		234,950			238,939
Total non-current liabilities		5,029,137			4,776,455
Total liabilities		6,689,833			6,802,636
Minority interest		5,530			5,095
Commitments and Contingencies
Stockholders’ Equity
Common stock; $.01 par value; 500,000,000 shares authorized; 100,000,000 shares at March 31, 2004 and at December 31, 2003 issued and outstanding		1,000			1,000
Additional paid-in capital		2,406,771			2,403,429
Retained earnings		41,260			11,025
Accumulated other comprehensive (loss)/gain		(3,176	)		21,802
Total stockholders’ equity		2,445,855			2,437,256
Total Liabilities and Stockholders’ Equity	$	9,141,218		$	9,244,987

See notes to consolidated financial statements.

5

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)

For the Three Months Ended March 31, 2004 and March 31, 2003
(Unaudited)

	Common				Additional					Accumulated Other			Total
					Paid-in		Retained			Comprehensive			Stockholders’
(In thousands)	Stock		Shares		Capital		Earnings/(Deficit)			(Loss)/Income			Equity/(Deficit)
(Balances at December 31, 2002 (Predecessor Company)	$	—		—	$	2,227,692	$	(2,828,933	)	$	(94,958	)	$	(696,199	)
Net Loss								(12,632	)					(12,632	)
Foreign currency translation adjustments and other											13,090			13,090
Deferred unrealized loss on derivatives, net											(57,136	)		(57,136	)
Comprehensive loss for the three months ended March 31, 2003														(56,678	)
Balances at March 31, 2003 (Predecessor Company)	$	—	$	—	$	2,227,692	$	(2,841,565	)	$	(139,004	)	$	(752,877	)
Balances at December 31, 2003 (Reorganized NRG)	$	1,000		100,000	$	2,403,429	$	11,025		$	21,802		$	2,437,256
Net Income								30,235						30,235
Foreign currency translation adjustments and other											(2,413	)		(2,413	)
Deferred unrealized loss on derivatives, net											(22,565	)		(22,565	)
Comprehensive gain for the three months ended March 31, 2004														5,257
Equity based compensation expense						3,342								3,342
Balances at March 31, 2004 (Reorganized NRG)	$	1,000		100,000	$	2,406,771	$	41,260		$	(3,176	)	$	2,445,855

See notes to consolidated financial statements.

6

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Reorganized			Predecessor
	NRG			Company
	Three Months Ended
	March 31,
(In thousands)	2004			2003
Cash Flows from Operating Activities
Net Income/(loss)	$	30,235		$	(12,632	)
Adjustments to reconcile net loss to net cash provided (used) by operating activities
Distributions in excess of (less than) than equity in earnings of unconsolidated affiliates		19,709			(16,897	)
Depreciation and amortization		59,114			70,900
Amortization of debt issuance costs		17,586			6,812
Amortization of debt discount/(premium)		6,969			—
Deferred income taxes		11,948			35,300
Minority interest		1,428			(217	)
Unrealized (gains)/losses on derivatives		(5,393	)		23,801
Asset impairment		—			24,289
Write downs and losses on sale of equity method investments		1,738			16,591
(Gain)/loss on sale of discontinued operations		—			(220,602	)
Amortization of power contracts and emission credits		22,747			—
Cash provided (used) by changes in certain working capital items, net of acquisition affects
Accounts receivable		(29,674	)		(60,191	)
Xcel Energy settlement receivable		288,000			—
Accrued income taxes		(392	)		(8,835	)
Inventory		21,035			33,436
Prepayments and other current assets		29,793			(59,538	)
Accounts payable		(2,521	)		4,378
Accounts payable — affiliates		543			2,237
Accrued property, sales and other taxes		(6,435	)		10,542
Accrued salaries, benefits and related costs		12,632			(4,978	)
Accrued interest		34,724			58,971
Other current liabilities		(169,410	)		371
Cash used by changes in other assets and liabilities		5,779			7,792
Net Cash Provided (Used) by Operating Activities		350,155			(88,470	)
Cash Flows from Investing Activities
Proceeds on sale of equity method investments		2,500			65,280
Investments in equity method investments and projects		(476	)		(224	)
Decrease in notes receivable (net)		15,940			3,949
Capital expenditures		(34,728	)		(16,488	)
(Increase)/decrease in restricted cash and trust funds		(17,714	)		11,688
Net Cash (Used) Provided by Investing Activities		(34,478	)		64,205
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt, net		486,028			3,822
Deferred debt issuance costs		(7,233	)		—
Principal payments on short and long-term debt		(516,912	)		(27,580	)
Net Cash Used by Financing Activities		(38,117	)		(23,758	)
Change in Cash from Discontinued Operations		3,192			25,743
Effect of Exchange Rate Changes on Cash and Cash Equivalents		(401	)		(27,044	)
Net Increase (Decrease) in Cash and Cash Equivalents		280,351			(49,324	)
Cash and Cash Equivalents at Beginning of Period		552,175			361,353
Cash and Cash Equivalents at End of Period	$	832,526		$	312,029

See notes to consolidated financial statements.

7

NRG ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization

General

     NRG Energy, Inc., or “NRG Energy”, “we”, “our”, or “us” is a wholesale power generation 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 and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type, and dispatch levels. We seek to maximize operating income through the efficient procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

     We were formed in 1992 as the non-regulated subsidiary of Northern States Power, or “NSP”, which was itself merged into New Century Energies, Inc. to form Xcel Energy, Inc., or “Xcel Energy” in 2000. While owned by NSP and later by Xcel Energy, we pursued a high growth strategy focused on power plant acquisitions, high leverage and aggressive development, including site development and turbine orders. In 2002, a number of factors, most notably the prices paid by us for our acquisitions of turbines, development projects and plants, combined with the overall downturn in the power generation industry, triggered a credit rating downgrade (below investment grade), which in turn, precipitated a severe liquidity situation. On May 14, 2003, we and 25 of our direct and indirect wholly owned subsidiaries commenced voluntary petitions under chapter 11 of the bankruptcy code in the United States Bankruptcy Court for the Southern District of New York. On November 24, 2003, the bankruptcy court entered an order confirming a plan of reorganization, for NRG Energy and four of our subsidiaries, and the plan became effective on December 5, 2003. On November 25, 2003, the bankruptcy court entered an order confirming the plan of reorganization for 21 of our subsidiaries, and the plan became effective on December 23, 2003. As of March 31, 2004, three entities remain in bankruptcy. Two entities have been deconsolidated and are accounted for under the cost method as we have effectively ceased control of the entities. Those entities are NRG Nelson Turbine, LLC and LSP-Nelson Energy LLC. The other entity, NRG McClain LLC, is shown as a discontinued operation since it was held for sale prior to filing for bankruptcy.

     As part of the NRG plan of reorganization, Xcel Energy relinquished its ownership interest in us and we became an independent public company upon our emergence from bankruptcy on December 5, 2003. We no longer have any material affiliation or relationship with Xcel Energy. As part of that reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes by distributing a combination of equity and up to $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used a substantial portion of the proceeds of a recent note offering and borrowings under a new credit facility, the “Refinancing Transactions,” to retire approximately $1.7 billion of project-level debt on December 23, 2003. In January 2004, we used proceeds of an additional note offering to repay $503.5 million of the outstanding borrowings under our new credit facility.

     As of March 31, 2004, we owned interests in 72 power projects in seven countries having an aggregate net generation capacity of approximately 18,200 MW. Approximately 7,900 MW of our capacity consists of merchant power plants in the Northeast region of the United States. Certain of these assets are located in transmission constrained areas, including approximately 1,400 MW of “in-city” New York City generation capacity and approximately 750 MW of southwest Connecticut generation capacity. We also own approximately 2,500 MW of capacity in the South Central region of the United States, with approximately 1,900 MW of that capacity supported by long-term power purchase agreements. Our assets in the West Coast region of the United States consist of approximately 1,300 MW of capacity with the majority of such capacity owned via our 50% interest in West Coast Power, LLC, or “West Coast Power.” Our assets in the West Coast region are supported by a power purchase agreement with the California Department of Water Resources that runs through December 2004.

     Our principal domestic generation assets consisted of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 48%, 26% and 26% of our total domestic generation capacity, respectively. In addition, 45% of our generating facilities have some capability to combust duel fuels. We also own interests in plants having a net generation capacity of approximately 3,000 MW in various international markets, including Australia, Europe and Latin America. We perform our own power marketing through our energy marketing subsidiary, NRG Power Marketing, Inc., or “PMI” which, is focused on maximizing the value of our North American assets by providing centralized contract origination and management services, and through the efficient procurement and management of fuel and the sale of energy and related products in the spot, intermediate and long-term markets.

8

     We were incorporated as a Delaware corporation on May 29, 1992. Our headquarters and principal executive offices are located at 901 Marquette Avenue, Suite 2300, Minneapolis, Minnesota, 55402. Our telephone number is (612) 373-5300. Our Internet website is http://www.nrgenergy.com. Our recent annual reports, quarterly reports, current reports and other periodic filings are available free of charge through our Internet website.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation

     As used in this Quarterly Report, “Predecessor Company” refers to the Company prior to its emergence from bankruptcy. “Reorganized NRG” refers to the Company after its emergence from bankruptcy.

     Between May 14, 2003 and December 5, 2003, we operated as a debtor-in-possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of Statement of Position 90-7,“Financial Reporting by Entities in Reorganization Under the Bankruptcy Code,” or“SOP 90-7”.

     The accompanying unaudited interim consolidated financial statements have been prepared in accordance with the Securities and Exchange Commission’s or “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 we follow are set forth in Note 2 to the Company’s financial statements in its Annual Report on Form 10-K for the year ended December 31, 2003, or “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 consolidated financial statements contain all material adjustments necessary to present fairly our consolidated financial position as of March 31, 2004 and December 31, 2003, the results of its operations and stockholders’ equity/(deficit) for the three months ended March 31, 2004 and 2003, and its cash flows for the three months ended March 31, 2004 and 2003. Certain prior-year amounts have been reclassified for comparative purposes.

     In connection with our emergence from bankruptcy, we adopted Fresh Start Reporting, or “Fresh Start” on December 5, 2003, in accordance with the requirements of SOP 90-7. The application of SOP 90-7 resulted in the creation of a new reporting entity. Under Fresh Start, our reorganization value was allocated to our assets and liabilities on a basis substantially consistent with purchase accounting in accordance with Statement of Financial Accounting Standards No. 141,“Business Combinations.”

Comparability of Financial Information

     Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start. A black line has been drawn on the accompanying Consolidated Financial Statements to separate and distinguish between Reorganized NRG and the Predecessor Company.

Note 3 — Discontinued Operations

     SFAS No. 144 requires that discontinued operations be valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions our management considered cash flow analyses and offers related to the assets and businesses. This amount is included in income on discontinued operations, net of income taxes in the accompanying Consolidated Statements of Operations. In accordance with SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

     We have classified certain business operations, and gains/(losses) recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification. The financial results for all of these businesses have been accounted for as discontinued operations. Accordingly, current period operating results and prior periods have been restated to report the operations as discontinued.

     For the three months ended March 31, 2004 discontinued operations included our McClain, Penobscot Energy Recovery Company (PERC) and Compania Boliviana De Energia

9

Electrica S.A. Bolivian Power Company Limited, or “Cobee” projects. For the three months ended March 31, 2003 discontinued operations included our McClain, PERC, Cobee, Killingholme, NEO Landfill Gas, Inc., or “NLGI”, three NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC), Timber Energy Resources, Inc., or “TERI”, Cahua and Energia Pacasmayo projects. Summarized results of operations of discontinued operations were as follows:

	Reorganized NRG		Predecessor Company
	Three Months Ended		Three Months Ended
	March 31, 2004		March 31, 2003
	(In thousands)
Operating revenues	$	37,974	$	51,215
Operating & other expenses		34,530		79,780
Pretax income/(loss) from operations of discontinued components		3,444		(28,565	)
Income tax expense		1,053		679
Income/(loss) from operations of discontinued components		2,391		(29,244	)
Disposal of discontinued components — gain (net)		—		190,794
Net income on discontinued operations	$	2,391	$	161,550

     The assets and liabilities of the discontinued operations are reported in the balance sheets as of March 31, 2004 and December 31, 2003 as discontinued operations. The major classes of assets and liabilities are presented by geographic area in the following table. As of March 31, 2004, within our Power Generation Segment, the PERC and McClain projects are included in the Other North America classification and the Cobee project is included in the Other International classification.

	Power Generation
	Other North		Other
March 31, 2004	America		International		Total
	(In thousands)
Cash	$	2,846	$	5,568	$	8,414
Restricted cash		19,913		—		19,913
Receivables, net		5,342		7,567		12,909
Inventory		3,961		842		4,803
Prepaids and other current assets		597		2,139		2,736
Current assets — discontinued operations	$	32,659	$	16,116	$	48,775
PP&E, net	$	206,175	$	35,152	$	241,327
Non-current deferred tax asset		—		31,336		31,336
Other non-current assets		2,282		2,130		4,412
Non-current assets — discontinued operations	$	208,457	$	68,618	$	277,075
Current portion of long-term debt	$	1,445	$	9,583	$	11,028
Accounts payable — trade		2,043		3,300		5,343
Accrued liabilities		2,266		4,504		6,770
Other current liabilities		652		—		652
Current liabilities — discontinued operations	$	6,406	$	17,387	$	23,793
Long-term debt	$	23,705	$	14,507	$	38,212
Minority interest		33,028		315		33,343
Other accrued liabilities		22		—		22
Other non-current liabilities		158,055		5,318		163,373
Non-current liabilities — discontinued operations	$	214,810	$	20,140	$	234,950

     As of December 31, 2003, within our Power Generation Segment, the PERC and McClain projects are included in the Other North America classification and the Cobee project is included in the Other International classification.

	Power Generation
	Other North		Other
December 31, 2003	America		International		Total
			(In thousands)
Cash	$	4,063	$	7,543	$	11,606
Restricted cash		19,184		—		19,184
Receivables, net		7,390		6,151		13,541
Inventory		4,109		753		4,862
Prepaids and other current assets		405		2,797		3,202

10

	Power Generation
	Other North			Other
December 31, 2003	America			International		Total
				(In thousands)
Current assets — discontinued operations	$	35,151		$	17,244	$	52,395
PP&E, net	$	206,175		$	35,671	$	241,846
Non-current deferred tax asset		—			31,469		31,469
Other non-current assets		2,492			2,092		4,584
Non-current assets — discontinued operations	$	208,667		$	69,232	$	277,899
Current portion of long-term debt	$	1,422		$	9,205	$	10,627
Accounts payable — trade		(247	)		3,571		3,324
Accrued liabilities		2,440			3,981		6,421
Other current liabilities		5,989			—		5,989
Current liabilities — discontinued operations	$	9,604		$	16,757	$	26,361
Long-term debt	$	23,640		$	19,779	$	43,419
Minority interest		31,879			315		32,194
Other non-current liabilities		158,853			4,473		163,326
Non-current liabilities — discontinued operations	$	214,372		$	24,567	$	238,939

     Killingholme— During third quarter 2002, we recorded an impairment charge of $477.9 million. In January 2003, we completed the sale of our interest in the Killingholme project to our lenders for a nominal value and forgiveness of outstanding debt with a carrying value of approximately $360.1 million at December 31, 2002. The sale of our interest in the Killingholme project and the release of debt obligations resulted in a gain on sale in the first quarter of 2003 of approximately $191.2 million. The gain results from the write-down of the project’s assets in the third quarter of 2002 below the carrying value of the related debt.

     NLGI— During 2002, we recorded an impairment charge of $12.4 million related to subsidiaries of NLGI, an indirect wholly owned subsidiary of NRG Energy. The charge was related largely to asset impairments based on a revised project outlook. During the quarter ended March 31, 2003, we recorded impairment charges of $23.6 million related to subsidiaries of NLGI and a charge of $14.5 million to write off our 50% investment in Minnesota Methane, LLC. Through April 30, 2003, NRG Energy and NLGI failed to make certain payments causing a default under NLGI’s term loan agreements. In May 2003, the project lenders to the wholly-owned subsidiaries of NLGI and Minnesota Methane LLC foreclosed on our membership interest in the NLGI subsidiaries and our equity interest in Minnesota Methane LLC. There was no material gain or loss recognized as a result of the foreclosure.

     TERI— During 2002, we recorded an impairment charge of $11.7 million based on a revised project outlook. In September 2003, we completed the sale of TERI, a biomass waste-fuel power plant located in Florida and a wood processing facility located in Georgia, to DG Telogia Power, LLC. The sale resulted in net proceeds of approximately $1.0 million. We entered into an agreement to sell the wood processing facility on behalf of DG Telogia Power, LLC. This sale was completed during fourth quarter 2003 and we received cash consideration of approximately $1.0 million, resulting in a net gain on sale of approximately $1.0 million.

     Peru Projects— In November 2003, we completed the sale of the Cahua and Pacasmayo (Peruvian Assets) resulting in net cash proceeds of approximately $16.2 million and a loss of $36.9 million. In addition, we expect to receive an additional consideration adjustment of approximately $0.6 million during 2004.

     NEO Corporation— In August of 1995, we entered into a Marketing, Development and Joint Proposing Agreement, or “the Marketing Agreement”, with Cambrian Energy Development LLC, or “Cambrian.” Various claims had arisen in connection with this Marketing Agreement. In November 2003, we entered into a Settlement Agreement with Cambrian where we agreed to transfer our 100% interest in three gasco projects (NEO Ft. Smith, NEO Phoenix and NEO Woodville).

     McClain— We reviewed the recoverability of our McClain assets pursuant to SFAS No. 144 and recorded a charge of $100.7 million in the second quarter of 2003. On August 14, 2003, NRG’s Board of Directors approved a plan to sell its 77% interest in McClain Generating Station, a 520 MW combined-cycle, natural gas-fired facility located in New Castle, Oklahoma. On August 18, 2003, we entered into an Asset Purchase Agreement with Oklahoma Gas & Electric Company pursuant to which we would, subject to the satisfaction of certain conditions, sell all of the McClain assets in a sale pursuant to Section 363 of the Bankruptcy Codes as part of McClain’s Chapter 11 proceeding that was subsequently filed on August 19, 2003.

     As a result of the formalization of the plan to sell the McClain assets and the filing of petition under the Bankruptcy Code by McClain, McClain is being accounted for as a discontinued operation.

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     As part of our effort to seek alternative transactions that would provide greater value and in accordance with the bidding procedures approved by the Bankruptcy Court, we conducted an auction for the sale of McClain’s assets, however no bids were submitted for the purchase of the assets. The Bankruptcy Court entered an order approving the terms of the sale with Oklahoma Gas & Electric or “OG&E” free and clear of all liens. The closing of the sale is subject to various closing conditions including approval by the Federal Energy Regulatory Commission. OG&E and McClain filed a joint application requesting that FERC approve the transaction on August 26, 2003. FERC issued an order on December 18, 2003 setting the matter for hearings. The hearings will specifically address the adequacy of transmission system improvements proposed by OG&E as mitigation for OG&E’s increased market concentration in generation as a result of the transaction. Hearings are scheduled to start on August 3, 2004. Upon consummation of the asset sale, the proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility.

     Penobscot Energy Recovery Company (PERC) —During the first quarter of 2004, we received board authorization to proceed with the sale of our interest in PERC to SET PERC Investment, LLC which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of $17.4 million, resulting in an immaterial gain.

     Cobee —During the first quarter of 2004, we entered into an agreement for the sale of our interest in our Cobee project to Globeleq Holdings Limited, which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of approximately $50.0 million, resulting in an immaterial gain.

     Batesville —In May, 2004 we reached an agreement to sell our 100 percent interest in an 837 megawatt generating plant in Batesville, Mississippi to Complete Energy Partners, LLC. We expect to realize cash proceeds of $26.5 million, subject to certain purchase price adjustments and transaction costs. No material gain or loss is expected upon the completion of the sale. Our Batesville facilities operations were not treated as discontinued operations during the first quarter of 2003 as they did not meet the appropriate criteria as of March 31, 2004.

Note 4 — Write Downs and Losses on Sales of Equity Method Investments

     Write downs and (gains)/losses on sales of equity method investments recorded in the consolidated statement of operations includes the following:

	Reorganized			Predecessor
	NRG			Company
	Three Months			Three Months
	Ended			Ended
	March 31, 2004			March 31, 2003
	(In thousands)
Calpine Cogeneration	$	(235	)	$	—
Loy Yang		1,973			—
NEO Corporation — Minnesota Methane		—			14,453
Kondapalli		—			1,293
ECKG		—			845
Total write downs and losses of equity method investments	$	1,738		$	16,591

     Calpine Cogeneration —In January 2004, we executed an agreement to sell our 20% interest in Calpine Cogeneration Corporation to Calpine Power Company. The transaction closed in March 2004 and resulted in net cash proceeds of $2.5 million and a net gain of $0.2 million.

     Loy Yang —During first quarter of 2004, we wrote down our investment in Loy Yang by $2.0 million due to recent estimates of the expected sales proceeds. In April 2004, we completed the sale of our 25.4% interest in Loy Yang to Great Energy Alliance Corporation, which resulted in net cash proceeds of $26.7 million. No material gain or loss is expected upon completion of the sale.

     NEO Corporation — Minnesota Methane —We recorded an impairment charge of $12.3 million during 2002 to write-down our 50% investment in Minnesota Methane. We recorded an additional impairment charge of $14.5 million during the first quarter of 2003. These charges were related to a revised project outlook and management’s belief that the decline in fair value was other than temporary. In May 2003, the project lenders to the wholly-owned subsidiaries of NEO Landfill Gas, Inc. and Minnesota Methane LLC foreclosed on our membership interest in the NEO Landfill Gas, Inc. subsidiaries and our equity interest in Minnesota Methane LLC. Upon completion of the foreclosure, we recorded a gain of $2.2 million. This gain resulted from the release of certain obligations.

     Kondapalli— In the fourth quarter of 2002, we wrote down our investment in Kondapalli by $12.7 million due to recent estimates of sales value, which indicated an impairment of our book value that was considered to be other than temporary. On January 30, 2003, we signed a sales agreement with the Genting Group of Malaysia, or “Genting”, to sell our 30% interest in Lanco Kondapalli Power Pvt

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     Ltd, or “Kondapalli”, and a 74% interest in Eastern Generation Services (India) Pvt Ltd (the O&M company). Kondapalli is based in Hyderabad, Andhra Pradesh, India, and is the owner of a 368 MW natural gas fired combined cycle gas turbine. In the first quarter of 2003, we wrote down our investment in Kondapalli by $1.3 million based on the final sales agreement. The sale closed on May 30, 2003 resulting in net cash proceeds of approximately $24 million and a gain of approximately $1.8 million.

     ECKG— In September 2002, we announced that we had reached agreement to sell our 44.5% interest in the ECKG power station in connection with our Csepel power generating facilities, and our interest in Entrade, an electricity trading business, to Atel, an independent energy group headquartered in Switzerland. The transaction closed in January 2003 and resulted in cash proceeds of $65.3 million and a net loss of less than $1.0 million

Note 5 — Reorganization, Restructuring and Impairment Charges

     Reorganization, restructuring and impairment charges included in operating expenses in the Consolidated Statements of Operations include the following:

	Reorganized NRG		Predecessor Company
	Three Months Ended		Three Months Ended
	March 31, 2004		March 31, 2003
	(In thousands)
Impairment charges	$	—	$	666
Reorganization charges		6,250		—
Restructuring charges		—		21,470
Total	$	6,250	$	22,136

     We reviewed the recoverability of our long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, we recorded no impairment charges for the three months ended March 31, 2004 and $0.7 million for the three months ended March 31, 2003.

     We incurred total reorganization charges of approximately $6.3 million for the three months ended March 31, 2004. All reorganization costs have been incurred since we filed for bankruptcy in May 2003. These costs consist of bankruptcy related charges primarily related to professional fees.

     We incurred total restructuring charges of approximately $21.5 million for the three months ended March 31, 2003. These costs consist of employee separation costs and advisor fees. All amounts were paid during the first half of 2003.

Note 6 — Asset Retirement Obligation

     Effective January 1, 2003, we 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, 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.

     We identified certain retirement obligations within our power generation segments related to our North America projects in the South Central region, the Northeast region, Australia, and our non-generation operations. These asset retirement obligations are related primarily to the future dismantlement of equipment on leased property and environment obligations related to ash disposal site closures. We 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 $2.6 million increase to property, plant and equipment and a $4.2 million increase to other long-term obligations. The cumulative effect of adopting SFAS No. 143 was a $0.6 million increase to depreciation expense and a $1.6 million increase to cost of majority-owned operations, as we considered the cumulative effect to be immaterial.

     The following represents the balances of the asset retirement obligation as of January 1, 2004 and the additions and accretion of the asset retirement obligation for the three months ended March 31, 2004, which is included in other long-term obligations in the consolidated balance sheet.

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			Accretion for Three
	Beginning Balance		Months Ended		Ending Balance
Description	Jan. 1, 2004		March 31, 2004		March 31, 2004
			(In thousands)
South Central Region	$	2,638	$	45	$	2,683
Northeast Region		11,750		199		11,949
Australia		9,438		1,199		10,637
Non-Generation		1,334		23		1,357
Alternative Energy		834		14		848
Total	$	25,994	$	1,480	$	27,474

Note 7 — Inventory

     Inventory, which is stated at the lower of weighted average cost or market, consisted of:

	March 31,		December 31,
	2004		2003
	(In thousands)
Fuel oil	$	52,524	$	75,272
Coal		62,724		59,555
Natural gas		315		856
Other fuels		87		75
Spare parts		62,406		61,918
Emission credits		4,478		4,478
Other		182		169
Total inventory	$	182,716	$	202,323

Note 8 — Property, Plant and Equipment

     The major classes of property, plant and equipment were as follows:

	March 31,			December 31,
	2004			2003
	(In thousands)
Facilities and equipment	$	4,140,537		$	4,055,700
Land and improvements		125,941			123,061
Office furnishings and equipment		17,988			17,953
Construction in progress		105,810			149,835
Total property, plant and equipment		4,390,276			4,346,549
Accumulated depreciation		(71,215	)		(12,555	)
Net property, plant and equipment	$	4,319,061		$	4,333,994

Note 9 — Summarized Financial Information of Affiliates

     We have a 50% interest in one company (West Coast Power LLC) that was considered significant, as defined by applicable SEC regulations, which is accounted for as an equity method investment.

West Coast Power LLC Summarized Financial Information

     For the three months ended March 31, 2004, we recorded equity earnings of $6.0 million for West Coast Power after adjustments for the reversal of $2.0 million project level depreciation expense, offset by a decrease in earnings related to $31.0 million amortization of the intangible asset for the California Department of Water Resources, or “CDWR” contract. As a result of pushing down the impact of Fresh Start to the projects balance sheet we established a contract based intangible asset with a one year remaining life, consisting of the value of West Coast Power’s CDWR energy sales contract. In accordance with SOP 90-7, the carrying value of this intangible asset was reduced by $1.0 million, as a result of allocating the reduction of our tax valuation allowance to our intangible assets (see Notes 10 and 16). The following table summarizes financial information for West Coast Power LLC, including interests owned by us and other parties for the periods shown below:

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Results of Operations

	Three Months		Three Months
	Ended March 31,		Ended March 31,
(In millions)	2004		2003
Operating revenues	$	283	$	259
Operating income	$	70	$	60
Net income (pre-tax)	$	70	$	59

Financial Position

	March 31,		December 31,
(In millions)	2004		2003
Current assets	$	286	$	257
Other assets		446		454
Total assets	$	732	$	711
Current liabilities	$	66	$	55
Other liabilities		8		8
Equity		658		648
Total liabilities and equity	$	732	$	711

     In April 2004, NRG Energy, West Coast Power, and Dynegy, reached a settlement agreement relating to FERC claims regarding market behavior in 2000 and 2001. The parties, who will enter into a definitive settlement, include FERC, Pacific Gas and Electric Company, Southern California Edison, The California Department of Water Resources, the California Electricity Oversight Board and the California Public Utilities Commission, or “CPUC.”

     Under the terms of the settlement, which must be approved by FERC and the CPUC, West Coast Power will not collect past due receivables from the California Independent System Operator and the California Power Exchange for power provided during the settlement period of June 2000 through January 2001. In addition, West Coast Power will make a cash payment of approximately $22.5 million to escrow accounts for ultimate distribution to purchasers in the California energy markets. In return, the parties to this settlement will drop their claim for any additional refunds from West Coast Power and all FERC investigations in this matter will be dismissed.

     West Coast Power and NRG Energy are fully reserved for both the past due receivables and the cash settlement as of March 31, 2004.

Note 10 — Intangible Assets

Reorganized NRG

     Upon the adoption of Fresh Start, we established certain intangible assets for power sales agreements and plant emission allowances. These intangible assets will be amortized over their respective lives based on a straight-line or units of production basis to resemble our realization of such assets.

     Power sale agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. The weighted average remaining amortization period is 3 years for the power sale agreements. Emission allowances will be amortized as additional fuel expense based upon the actual level of emissions from the respective plants through 2023. Aggregate amortization recognized for the three months ended March 31, 2004 was approximately $16.8 million. The annual aggregate amortization for each of the five succeeding years is expected to approximate $54.6 million in year one, $35.9 million in year two, $29.2 million in years three and four, and $22.3 million in year five for both the power sale agreements and emission allowances. The expected annual amortization of these amounts is expected to change as we relieve our tax valuation allowance, as explained below.

     For the three months ended March 31, 2004, we reduced our tax valuation allowance by $5.5 million (see Note 16) and recorded a corresponding reduction of $4.5 million related to our intangible assets at our wholly-owned subsidiaries. The remaining $1.0 million was recorded as a reduction to our intangible asset related to our equity investments (see Note 9). In accordance with SOP 90-7, any future benefits from reducing the valuation allowance should first reduce intangible assets until exhausted, and thereafter be recorded as a direct addition to paid-in-capital.

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Intangible assets consisted of the following:

	Power Sale			Emission
(In thousands)	Agreements			Allowances			Total
Original balance as of December 6, 2003	$	66,114		$	373,518		$	439,632
Amortization		(5,230	)		—			(5,230	)
Balance as of December 31, 2003		60,884			373,518			434,402
Tax valuation adjustment		(909	)		(3,570	)		(4,479	)
Amortization		(10,568	)		(6,270	)		(16,838	)
Balance as of March 31, 2004	$	49,407		$	363,678		$	413,085

Predecessor Company

     We had intangible assets of $27 million at March 31, 2003, which were not amortized and consisted of goodwill. We had intangible assets of $48.8 million at March 31, 2003, which were amortized and consisted of service contracts. Aggregate amortization expense recognized for the three months ended March 31, 2003 was approximately $1.1 million.

Note 11 — Derivative Instruments and Hedging Activities

     SFAS No. 133 requires us to record all derivatives on the balance sheet as assets or liabilities at fair value. For derivatives designated as cash flow hedges, the effective portion of the changes in fair value of the derivatives are recorded in Accumulated Other Comprehensive Income (OCI) and subsequently recognized in earnings when the hedged items impact income. For derivatives designated as hedges of the fair value of assets or liabilities, the changes in fair value of both the derivatives and the hedged items are recorded in current earnings. Changes in the fair value of non-hedge derivatives will be immediately recognized in earnings.

     SFAS No. 133 applies to our 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. SFAS No. 133 also applies to various interest rate financial instruments used to mitigate the risks associated with movements in interest rates, foreign exchange contracts used to reduce the effect of fluctuating foreign currencies on foreign denominated investments and other transactions.

Accumulated Other Comprehensive Income

     The following table summarizes the effects of SFAS No. 133 on our OCI balance for the three months ended March 31, 2004:

	Reorganized NRG
	Energy			Interest			Foreign
(Gains/(Losses) In thousands)	Commodities			Rate			Currency			Total
Accumulated OCI balance at December 31, 2003	$	(1,953	)	$	1,600		$	(170	)	$	(523	)
Unwound from OCI during period:
— Due to unwinding of previously deferred amounts		400			(4	)		170			566
Mark to market of hedge contracts		(13,718	)		(9,413	)		—			(23,131	)
Accumulated OCI balance at March 31, 2004	$	(15,271	)	$	(7,817	)	$	—		$	(23,088	)
Gains/(Losses) expected to unwind from OCI during next 12 months	$	(15,271	)	$	(77	)	$	—		$	(15,348	)

     Losses of $0.6 million were reclassified from OCI to current period earnings during the three months ended March 31, 2004, due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the three months ended March 31, 2004, we recorded losses in OCI of approximately $23.1 million 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 March 31, 2004 was an unrecognized loss of approximately $23.1 million. We expect $15.3 million of deferred net losses on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

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     The following table summarizes the effects of SFAS No. 133 on NRG Energy’s OCI balance as of March 31, 2003:

	Predecessor Company
	Energy			Interest			Foreign
(Gains/(Losses) In thousands)	Commodities			Rate			Currency			Total
Accumulated OCI balance at December 31, 2002	$	129,496		$	(102,957	)	$	(261	)	$	26,278
Unwound from OCI during period:
— Due to unwinding of previously deferred amounts		(18,361	)		(76	)		261			(18,176	)
Mark to market of hedge contracts		(25,924	)		(13,036	)		—			(38,960	)
Accumulated OCI balance at March 31, 2003	$	85,211		$	(116,069	)	$	—		$	(30,858	)

     Gains of $18.2 million were reclassified from OCI to current period earnings during the three months ended March 31, 2003 due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the three months ended March 31, 2003 we recorded losses in OCI of approximately $39.0 million 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 March 31, 2003 was an unrecognized loss of approximately $30.9 million.

Statement of Operations

     The following tables summarize the pre-tax effects of non-hedge derivatives on our statement of operations for the three months ended March 31, 2004:

	Reorganized NRG
	Energy					Foreign
(Gains/(Losses) In thousands)	Commodities			Interest Rate		Currency		Total
Revenue from majority owned subsidiaries	$	896		$	—	$	—	$	896
Equity in earnings of unconsolidated subsidiaries		(1,158	)		—		—		(1,158	)
Cost of operations		(503	)		—		—		(503	)
Interest expense		—			411		—		411
Total Statement of Operations impact before tax	$	(765	)	$	411	$	—	$	(354	)

     The following tables summarize the pre-tax effects of non-hedge derivatives on our statement of operations for the three months ended March 31, 2003:

	Predecessor Company
	Energy						Foreign
(Gains/(Losses) In thousands)	Commodities			Interest Rate			Currency		Total
Revenue from majority owned subsidiaries	$	(2,429	)	$	—		$	—	$	(2,429	)
Equity in earnings of unconsolidated subsidiaries		1,507			(222	)		—		1,285
Cost of operations		(11,778	)		—			92		(11,686	)
Interest expense		—			(12,239	)		—		(12,239	)
Total Statement of Operations impact before tax	$	(12,700	)	$	(12,461	)	$	92	$	(25,069	)

Energy Related Commodities

     We are exposed to commodity price variability in electricity, emission allowances and natural gas, oil and coal used to meet fuel requirements. In order to manage these commodity price risks, we entered 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. Certain of these transactions have been designated as cash flow hedges. We have accounted for these derivatives by recording the effective portion of the cumulative gain or loss on the derivative instrument as a component of OCI in stockholders’ deficit. We recognize deferred gains and losses into earnings in the same period or periods during which the hedged transaction affects earnings. Such reclassifications are included on the same line of the statement of operations in which the hedged item is recorded.

     No ineffectiveness was recognized on commodity cash flow hedges during the three months ended March 31, 2004 or March 31, 2003.

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     Our pre-tax earnings for the three months ended March 31, 2004 and 2003 were affected by an unrealized loss of $0.8 million and $12.7 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.

     During the three months ended March 31, 2004 and 2003, we reclassified losses of $0.4 million and gains of $18.4 million, respectively, from OCI to current-period earnings and expect to reclassify an additional $15.3 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

     At March 31, 2004, we had hedge and non-hedge energy related commodities financial instruments extending through May 2005.

Interest Rates

     To manage interest rate risk, we have entered into interest-rate swap agreements that fix the interest payments or the fair value of selected debt issuances. The qualifying swap agreements are accounted for as cash flow or fair value hedges. The effective portion of the cash flow hedges’ cumulative gains/losses are reported as a component of OCI in stockholders’ equity. These gains/losses are recognized in earnings as the hedged interest expense is incurred. The reclassification from OCI is included on the same line of the statement of operations in which the hedged item appears. The entire amount of the change in fair value hedges is recorded in the statement of operations along with the change in value of the hedged item.

     No ineffectiveness was recognized on interest rate swaps that qualify as hedges during the three months ended March 31, 2004.

     During the three months ended March 31, 2004, pre-tax earnings were increased by an unrealized gain of $0.4 million related to the change in fair value of one interest rate related derivative instrument. This instrument is a $400 million floating to fixed interest rate swap, which was not designated as an effective hedge of the expected cash flows at March 31, 2004. As of April 1, 2004, this instrument was designated as a cash flow hedge under SFAS No. 133. As a result, subsequent changes to its fair value will be deferred and recorded as part of other comprehensive income. Our pre-tax earnings for the three months ended March 31, 2003 were decreased by an unrealized loss of $12.5 million, associated with changes in the fair value of interest rate derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

     During the three months ended March 31, 2004 and March 31, 2003, we reclassified gains of $4,000 and $0.1 million, respectively, from OCI to current- period earnings and expect to reclassify approximately $0.1 million of deferred losses to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

     At March 31, 2004, we had interest rate derivatives instruments extending through June 2019.

Foreign Currency Exchange Rates

     To preserve the U.S. dollar value of projected foreign currency cash flows, we may hedge, or protect those cash flows if appropriate foreign hedging instruments are available.

     No ineffectiveness was recognized on foreign currency cash flow hedges during the three months ended March 31, 2004 or March 31, 2003.

     Our pre-tax earnings for the three months ended March 31, 2003 were increased by an unrealized gain of $0.1 million, associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133. There was no impact for the three months ended March 31, 2004.

     During the three months ended March 31,2004 and March 31, 2003, we reclassified losses of $0.2 million and $0.3 million, respectively from OCI to current period earnings and we do not expect to reclassify any deferred gains/losses to earnings during the next twelve months on foreign currency swaps accounted for as hedges.

Note 12 — Short Term Debt and Long Term Debt

     As part of and concurrent with our emergence from bankruptcy on December 5, 2003, certain senior unsecured credit facilities were terminated and defaults related to those facilities were eliminated.

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     As of March 31, 2004, we have made timely scheduled payments on interest and/or principal on all of our recourse debt and were not in default under any of our related recourse debt instruments. Additionally, we are not in default of any obligations to post collateral. As discussed below, our NRG McClain LLC Project debt is in default. However, a significant amount of our subsidiaries’ debt and other obligations contain terms that require that they be supported with letters of credit or cash collateral.

NRG Energy Corporate Debt

     On December 5, 2003 we entered into a $10.0 million promissory note with Xcel Energy. The note accrues interest at a rate of 3% per year, payable quarterly in arrears. All principal is due at maturity on June 5, 2006.

     On December 23, 2003, we and PMI entered into a Senior Secured Credit Facility for up to $1.45 billion, which is comprised of both long-term and short-term debt. Long-term debt included a $950.0 million, six and a half-year senior secured term loan and a $250.0 million letter of credit facility, funded with proceeds from the senior secured lenders. Principal and interest on the term loan is payable quarterly on March 31, June 30, September 30 and December 31 of each year. As of March 31, 2004, the interest rate on the term loan was 5.5%, based on LIBOR plus a credit spread. The LIBOR portion is subject to a floor of 1.5%.

     The $250.0 million funded letter of credit is reflected as a funded deposit on the March 31, 2004 balance sheet. As of March 31, 2004, $113.2 million in letters of credit had been issued under this facility, leaving $136.8 million available for future issuances. Expenses associated with the funded letter of credit include commitment fees on the undrawn portion of the letter of credit facility, participation fees for the credit-linked deposit and other fees.

     The short-term debt component of the Senior Secured Credit Facility is a four-year, $250.0 million revolving line of credit (the Corporate Revolver). Portions of the Corporate Revolver are available as a swing-line facility and as a revolving letter of credit sub-facility. As of March 31, 2004, the corporate revolver was undrawn. We pay a commitment fee of 1% on any undrawn portion of the Corporate Revolver, and interest on any borrowed amounts.

     On December 23, 2003, we issued $1.25 billion in 8% Second Priority Notes, due and payable on December 15, 2013. The 8% Second Priority Notes are general obligations of ours. They are secured on a second-priority basis by security interests in all of our assets. Subject to the liens securing our obligations under the Senior Secured Credit Facility and any other priority lien obligations, which will be secured on a first-priority basis by the same assets that secure the 8% Second Priority Notes. The 8% Second Priority Notes will be senior in right of payment to any future subordinated indebtedness. Interest on the 8% Second Priority Notes accrues at the rate of 8.0% per annum and is payable semi-annually in arrears on June 15 and December 15, commencing June 15, 2004.

     On January 28, 2004, we issued, at a premium, an additional $475.0 million in 8% Second Priority Notes under the same terms and indenture as the December 23, 2003 offering. Proceeds of the additional offering were used to prepay $503.5 million of the term loan under the Senior Secured Credit Facility, reducing the outstanding principal of the term loan from $950.0 million to $446.5 million. A scheduled principal payment on March 31, 2004 further reduced the outstanding principal of the term loan to $444.8 million. In January, 2004 we wrote-off $15.0 million of deferred financing costs (included in interest expense) related to the term loans which were repaid. In addition, we deferred an additional $7.2 million of financing costs related to the newly issued notes.

     On February 25, 2004, we amended our Senior Secured Credit Facility to remove an interest rate hedge mandate. The amendment provides us with additional flexibility in how we choose to mitigate interest-rate risk.

     On March 24, 2004, we executed an interest rate swap agreement to mitigate our floating-rate interest exposure associated with our Senior Secured Credit Facility. The swap agreement became effective March 26, 2004 and terminates March 31, 2006. Under the agreement, we agree to pay quarterly a fixed interest rate on a notional amount of $400.0 million, commencing on March 31, 2004, and receive quarterly a floating-rate interest rate payment on the same notional amount. The floating rate is based upon three-month LIBOR, subject to a floor.

     On March 24, 2004, we executed a second interest rate swap agreement to mitigate our fixed-rate interest exposure associated with our 8% Second Priority Notes. This swap agreement became effective March 26, 2004 and terminates December 15, 2013. The swap agreement has provisions for early termination that are linked to any prepayment of the 8% Second Priority Notes. Under the agreement, we agree to pay semi-annually in arrears, commencing June 15, 2004, a floating interest rate on a notional amount of $400.0 million, and receive semi-annually in arrears a fixed interest rate payment on the same notional amount. The floating interest rate is based upon six-month LIBOR plus a spread. Depending on market interest rates, we or the swap counterparty may be required to post collateral on a daily basis in support of both of these swaps, to the benefit of the other party.

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     On April 29, 2004, we amended our Senior Secured Credit Facility to give us the flexibility to enter into joint ventures from time to time with affiliates of our 21.5% stockholder, MatlinPatterson Global Opportunities Partners, L.P. (“MatlinPatterson”). Three representatives of MatlinPatterson are members of our board of directors. We paid the lenders and agent under our senior secured credit agreement a fee equal to 12.5 basis points, or approximately $1.2 million, for the amendment.

Project Debt Defaults

LSP Kendall Energy, LLC

     As part of our acquisition of the LS Power assets in January 2001, NRG Energy, through its indirect wholly owned subsidiary, LSP Kendall Energy, LLC (Kendall), acquired a $554.2 million credit facility. The facility is non-recourse to us and consists of a construction and term loan, working capital and letter of credit facility. Kendall is a party to four interest rate swaps intended to mitigate much of the interest rate risk associated with the Kendall debt. As of December 31, 2003 and March 31, 2004, there were borrowings totaling approximately $487.0 million and $484.5 million, respectively, outstanding. The facility’s interest rate was 2.46% as of March 31, 2004, excluding interest rate hedges. Kendall has timely met all principal and interest obligations under the credit facility.

     In May 2002, Kendall received a notice of default from Société Generale, the administrative agent under LSP-Kendall’s Credit and Reimbursement Agreement dated November 12, 1999. The notice asserted that an event of default had occurred under the Credit and Reimbursement Agreement as a result of liens filed against the Kendall project by various subcontractors. In consideration of the borrower’s implementation of a plan to remove the liens, and our indemnification pursuant to an Indemnity Agreement dated June 28, 2002, indemnifying the lenders to the Kendall project from any claims or damages relating to these liens or any dispute or action involving the project’s contractors, the administrative agent, with the consent of the required lenders under the Credit and Reimbursement Agreement, withdrew the notice of default and conditionally waived any default or event of default described therein.

     On August 25, 2003, Kendall entered into a Completion Extension and Amendment Agreement with the lenders and Société Generale whereby certain extensions were granted in respect of project construction, lien removal and other items. The Completion Extension and Amendment Agreement prohibits Kendall from making any distributions to equity owners until January 1, 2005, and thereafter only when certain conditions are met. Subsequent to execution of the Completion Extension and Amendment Agreement, the project defaulted under provisions requiring project completion. As of March 31, 2004, the Kendall debt was classified as current, due to the creditors’ ability to accelerate the debt based on the abovementioned default.

     In April 2004, Kendall executed an agreement with its lenders resolving the defaults under its credit facility. As required by this settlement agreement, Kendall prepaid $10.5 million in principal on its credit facility on April 21, 2004. Also in April, Kendall executed agreements with certain of its contractors, which resulted in these contractors receiving unsecured claims pursuant to the NRG Plan of Reorganization. Effective with the execution of those agreements, Kendall will no longer be in default with respect to the credit facility and the debt will no longer be classified as current.

NRG McClain LLC

     On November 28, 2001, NRG McClain LLC entered into a credit agreement with Westdeutsche Landesbank Girozentrale, New York Branch and various other lending institutions for a $181.0 million secured term loan (the McClain Secured Term Loan) and an $8.0 million working capital facility. As of December 31, 2003 and March 31, 2004, the outstanding amount under this facility was $156.5 million and $156.5 million, respectively. As of March 31, 2004, the interest rate on such outstanding borrowings was 4.625%.

     On September 17, 2002, NRG McClain LLC received notice from the agent bank that the project loan was in default as a result of our downgrades and of defaults on material obligations under the Energy Management Services Agreement. On August 19, 2003, NRG McClain signed an asset purchase agreement with Oklahoma Gas and Electric Company for substantially all of the assets of McClain and contemporaneously filed for bankruptcy pursuant to the asset purchase agreement. Upon consummation of the asset sale, the proceeds from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility.

     OG&E and McClain filed a joint application requesting that FERC approve the transaction on August 26, 2003. FERC issued an order on December 18, 2003 setting the matter for hearings. The hearings will specifically address the adequacy of transmission system improvements proposed by OG&E as mitigation for OG&E’s increased market concentration in generation as a result of the transaction.

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Hearings are scheduled to start on August 3, 2004. Approval of the transaction is not expected prior to the end of 2004. NRG McClain is recorded as a discontinued operation in the accompanying balance sheets.

NRG Peaker Finance Company LLC

     In June 2002, NRG Peaker Finance Company LLC, or “NRG Peakers,” an indirect wholly owned subsidiary of NRG Energy, completed the issuance of $325 million of Series A Floating Rate Senior Secured Bonds due 2019. The bonds bear interest at a floating rate equal to three-month LIBOR plus 1.07% (average of 2.20% for the quarter ending March 31, 2004) NRG Peaker entered into an interest rate swap by which NRG Peaker pays a fixed rate of 6.667% through the final maturity of the bonds. As of March 31, 2004, the outstanding amount on this facility was $311.4 million, unchanged from December 31, 2003.

     On May 13, 2003, XL Capital Assurance, or “XLCA,” as controlling party, accelerated the debt issued by NRG Peaker, rendering the debt immediately due and payable. On January 6, 2004, we and XLCA consummated a comprehensive restructuring arrangement which provides for, among other things, the provision of a letter of credit by us for the benefit of the secured parties in the NRG Peaker financing, the cure or waiver of all defaults under the original financing agreement and the mutual release of claims by the parties. As of March 31, 2004, NRG Peaker was not in default under its financing agreements.

Meriden Gas Turbines LLC

Meriden Gas Turbines LLC, or “MGT,” is a party to a $0.5 million Promissory Note and Security Agreement with PowerSource LLC, issued and entered into on February 13, 2003. MGT used the proceeds of the note issuance to allow the release of a lien and claim on certain MGT assets, and for costs associated with the transport of certain equipment to the MGT site. The note became due and payable on May 14, 2003. We expect to repay this note with the proceeds from the sale of the MGT assets in 2004.

Note 13 — Corporate Relocation Charges

     On March 16, 2004, we announced plans to implement a new regional business strategy and structure. The new structure calls for a reorganized leadership team and a corporate headquarters relocation to West Windsor, New Jersey. The corporate relocation is intended to increase our effectiveness in serving our plants and employees as well as our external stakeholders such as regulators, customers and investors. The corporate headquarters staff will be streamlined as part of the relocation, as functions are shifted to the regions. A reduction in the corporate staff of approximately 100 employees is expected. We currently have approximately 240 individuals at our Minneapolis headquarters. The transition of corporate headquarters is expected to begin in September 2004 and run through March 2005.

     We expect to incur $34.0 million of expenses in connection with corporate relocation charges. Relocating, recruiting and other employee-related transition costs are expected to be approximately $17.0 million. These costs and cash payments are expected to be incurred through first quarter of 2005. Severance and termination benefits of $9.1 million are expected to be incurred through first quarter of 2005 with cash payments being made through fourth quarter of 2005. Building lease termination costs and write-offs of fixed assets are expected to be $7.9 million. These costs are expected to be incurred through first quarter of 2005 with cash payments being made through fourth quarter of 2006. The restructuring liability is recorded at fair market value. A summary of the significant components of the restructuring liability is as follows:

	Balance at		Restructuring						Balance at
	December 31,		Related		Non-Cash		Cash		March 31,
(In thousands)	2003		Charges		Charges		Payments		2004
Employee related transition costs	$	—	$	1,116	$	—	$	—	$	1,116
Total	$	—	$	1,116	$	—	$	—	$	1,116

     As of March 31, 2004, the restructuring liability was $1.1 million and is included in other current liabilities on the consolidated balance sheet. Charges related to the employee related transition costs are recorded at our corporate level within our Other segment, in the corporate relocation charges line on the consolidated statement of operations.

Note 14 — Earnings Per Share

     Basic earnings per common share were computed by dividing net income by the weighted average number of common stock shares outstanding. Shares issued during the year are weighted for the portion of the year that they were outstanding. Shares of common stock granted to our officers and employees are included in the computation only after the shares become fully vested. Diluted earnings per

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share are computed in a manner consistent with that of basic earnings per share while giving effect to all potentially dilutive common shares that were outstanding during the period. The dilutive effect of the potential exercise of outstanding options to purchase shares of common stock is calculated using the treasury stock method. The reconciliation of basic earnings per common share to diluted earnings per share is shown in the following table:

	Reorganized NRG
	For the Three
	Months Ended
	March 31, 2004
	(In thousands,
	except per share data)
Basic earnings per share
Numerator:
Income from continuing operations	$	27,844
Income on discontinued operations, net of income taxes		2,391
Net income	$	30,235
Denominator:
Weighted average number of common shares outstanding		100,018
Income from continuing operations per share	$	0.28
Income on discontinued operations, net of income taxes per share.		0.02
Net income per share - basic	$	0.30
Diluted earnings per share
Numerator
Income from continuing operations	$	27,844
Income on discontinued operations, net of income taxes		2,391
Net income	$	30,235
Denominator:
Weighted average number of common shares outstanding		100,018
Incremental shares attributable to the assumed exercise of outstanding stock options (treasury stock method)		—
Incremental shares attributable to the issuance of unvested stock grants (treasury stock method)		—
Total dilutive shares		100,018
Income from continuing operations per share	$	0.28
Income on discontinued operations, net of income taxes per share		0.02
Net income per share - diluted	$	0.30

     For the three months ended March 31, 2004, 727,751 options have been excluded from the dilutive calculation as their exercise price exceeded the average market price of the common shares and therefore the effect would be anti-dilutive.

     Stock options:During March 2004, we issued stock option grants for 232,000 shares of common stock under the Long-Term Incentive Plan. 137,000 options were issued at a fair value of $19.90 per share and 95,000 options were issued at a fair value of $21.85 per share. These options have a three-year graded vesting schedule. Compensation expense recorded under the stock option grants for the three months ended March 31, 2004 was approximately $1.3 million.

     Restricted stock units:During March 2004, we issued 624,400 Restricted Stock Units or “RSUs” under the Long-Term Incentive Plan. 598,400 RSUs were issued at a fair value of $19.90 per unit. 26,000 RSUs were issued at a fair value of $21.85 per unit. These units cliff vest in three years. Compensation expense recorded under the RSUs for the three months ended March 31, 2004 was approximately $0.7 million. For purposes of computing earnings per share, nonvested RSUs are not considered outstanding for purposes of computing basic earnings per share; however, these units are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method.

     Deferred stock units:During March 2004, we issued 63,422 Deferred Stock Units or “DSU” under the Long-Term Incentive Plan at a fair value of $19.95 per unit. A DSU will entitle the grantee to receive either one share of common stock or RSU at the end of the deferral period of not less than one year. Compensation expense recorded under the DSUs for the three months ended March 31, 2004 was approximately $1.3 million. For the purposes of computing basic earnings per share, the DSU’s are considered outstanding upon grant on a weighted average basis.

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Note 15 — Segment Reporting

     In connection with our emergence from bankruptcy and the new management team, we determined that it was necessary to adjust our segment reporting disclosures to more closely align our disclosures with the realignment of our management team. Accordingly, we have expanded our domestic geographical disclosures and collapsed our international geographical disclosures related to our wholesale power generation segment. In addition, our other segments have been further refined. As a result of these changes, we have retroactively recast our prior period disclosures in a consistent manner.

     We conducted our business within five operating segments: Wholesale Power Generation, Alternative Energy, Thermal, Energy Marketing, and Operating Services. These segments are distinct components with separate operating results and management structures in place. The Thermal, Energy Marketing and Operating Services operating segments are aggregated into one reportable segment under the heading “Other Non-Generation” as they do not meet the threshold for separate disclosure. The Wholesale Power Generation operating segment is further disclosed within six significant domestic and foreign geographic areas: Northeast, South Central, West Coast, Other North America, Australia, and Other International. The “Other” category includes operations that do not meet the definition of an operating segment and corporate charges (primarily interest expense) that have not been allocated to the operating segments. Segment information for the three months ended March 31, 2004 and 2003 is as follows:

	For the Three Months Ended March 31, 2004
	Power Generation
	(In thousands)
			South					Other North
	Northeast		Central		West Coast			America			Australia
Operating Revenues	$	330,540	$	95,265	$	(3,322	)	$	33,418		$	62,229
Corporate Relocation		—		—		—			—			—
Reorganization charges		321		723		—			150			—
Write downs and losses on equity method investments		—		—		—			235			(1,973	)
Continuing operations before income taxes		87,428		11,377		1,363			(11,187	)		16,399
Income tax expense		—		—		2,852			347			3,264
Net Income (Loss) from continuing operations		87,428		11,377		(1,489	)		(11,534	)		13,135
Net Income (Loss) from discontinued operations		—		—		—			312			—
Net Income (Loss)		87,428		11,377		(1,489	)		(11,222	)		13,135
Balance Sheet Total assets	$	1,996,383	$	1,158,248	$	323,031		$	2,032,321		$	1,014,944

	For the Three Months Ended March 31, 2004
	(In thousands)
	Power
	Generation
	Other		Alternative		Other Non-
	International		Energy		Generation		Other			Total
Operating Revenues	$	48,332	$	13,653	$	41,019	$	33		$	621,167
Corporate Relocation		—		—		—		1,116			1,116
Reorganization charges		1		—		688		4,367			6,250
Write downs and losses on equity method investments		—		—		—		—			(1,738	)
Continuing operations before income taxes		12,316		546		8,772		(84,962	)		42,052
Income tax expense		4,060		4		165		3,516			14,208
Net Income (Loss) from continuing operations		8,256		542		8,607		(88,478	)		27,844
Net Income (Loss) from discontinued operations		2,079		—		—		—			2,391
Net Income (Loss)		10,335		542		8,607		(88,478	)		30,235
Balance Sheet Total assets	$	933,745	$	61,628	$	531,033	$	1,089,885		$	9,141,218

	For the Three Months Ended March 31, 2003
	Power Generation
	(In thousands)
				South					Other North
	Northeast			Central		West Coast			America			Australia
Operating Revenues	$	239,564		$	104,107	$	1,420		$	28,962		$	48,016
Restructuring and impairment charges		760			669		—			372			—
Write downs and losses on equity method investments		—			—		—			—			—
Continuing operations before income taxes		(20,750	)		9,947		23,999			(36,661	)		10,000
Income tax expense		—			—		36,180			891			517
Net Income (Loss) from continuing operations		(20,750	)		9,947		(12,181	)		(37,552	)		9,483
Net Income (Loss) from discontinued operations		—			—		—			(7,284	)		—
Net Income (Loss)		(20,750	)		9,947		(12,181	)		(44,836	)		9,483
Balance Sheet Total assets	$	2,684,922		$	1,346,385	$	477,360		$	2,699,631		$	511,564

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	For the Three Months Ended March 31, 2003
	(In thousands)
	Power Generation
	Other			Alternative			Non-
	International			Energy			Generation		Other			Total
Operating Revenues	$	46,257		$	13,374		$	39,878	$	(1,996	)	$	519,582
Restructuring and impairment charges		(3,573	)		—			16		23,892			22,136
Write downs and losses on equity method investments		(2,138	)		(14,453	)		—		—			(16,591	)
Continuing operations before income taxes		16,397			(14,422	)		7,468		(137,282	)		(141,304	)
Income tax expense		3,006			—			672		(8,388	)		32,878
Net Income (Loss) from continuing operations		13,391			(14,422	)		6,796		(128,894	)		(174,182	)
Net Income (Loss) from discontinued operations		203,986			(25,998	)		—		(9,154	)		161,550
Net Income (Loss)		217,377			(40,420	)		6,796		(138,048	)		(12,632	)
Balance Sheet Total assets	$	1,412,316		$	102,782		$	307,106	$	695,867		$	10,237,933

Note 16 — Income Taxes

     The income tax provisions for the three months ended March 31, 2004 and March 31, 2003 have been recorded on the basis that we and our U.S. subsidiaries will file a consolidated federal income tax return for 2004 and separate federal income tax returns for the period January 1 to December 5, 2003.

     Income taxes for the three months ended March 31, 2004 was a tax expense of $14.2 million compared to a tax expense of $32.9 million for the same period in 2003. The tax expense for the three months ended March 31, 2004 includes U.S. tax expense of $6.7 million and International tax expense of $7.5 million. The tax expense for the three months ended March 31, 2003 includes U.S. tax expense of $29.2 million and International tax expense of $3.7 million.

     For U.S. income tax purposes, the tax expense in 2004 is due to a reduction in deferred tax assets without a tax benefit for the corresponding reduction in valuation allowance. Due to the uncertainty of realization of deferred tax assets related to net operating losses and other temporary differences, our U.S. net deferred tax assets at December 5, 2003 were offset by a full valuation allowance of $1.3 billion in accordance with SFAS 109. SOP 90-7 requires reductions in the valuation allowance as of December 5, 2003 (date of emergence) should first reduce intangible assets until exhausted and thereafter be reported as a direct addition to paid-in-capital. Consequently, our effective tax rate in post Bankruptcy emergence years will not benefit from reductions in the valuation allowance. For 2003, the U.S. tax expense is due to an additional valuation allowance recorded against the deferred tax assets of NRG West Coast as a result of its conversion from a corporation to a disregarded entity for federal income tax purposes. Subsequent to the conversion, NRG West Coast will no longer be taxed as an entity separate from NRG Energy.

     The International tax expense for the first three months of 2004 and 2003 is due to the earnings in foreign jurisdictions.

     The effective income tax rate for the period ended March 31, 2004 differs from the statutory federal income tax rate of 35% primarily due to lower tax rates in foreign jurisdictions and to the SOP 90-7 requirement that reductions to the valuation allowance as of December 5, 2003 (date of emergence) should first reduce intangible assets until exhausted and thereafter be reported as a direct addition to paid-in-capital. The effective income tax rate for the period ended March 31, 2003 differs from the statutory federal income tax rate of 35% primarily due to limitation on tax benefits.

     As of March 31, 2004, the valuation allowance against U.S. and Foreign net operating loss carryforwards was $536.1 million and the valuation allowance against other deferred tax assets was $730.5 million. As of December 31, 2003, a valuation allowance of $559.7 million was provided to account for potential limitations on utilization of U.S. and Foreign net operating loss carryforwards, and a valuation allowance of $704.7 million was provided for other deferred tax assets. If unused, the U.S. net operating loss carryforward of $1.0 billion generated in 2002 and 2003 will expire by 2023. The Foreign net operating loss carryforwards have no expiration date.

Note 17 — Commitments and Contingencies

Legal Issues

California Wholesale Electricity Litigation and Related Investigations

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     People of the State of California ex. rel. Bill Lockyer, Attorney General, v. Dynegy, Inc. et al.,United States District Court, Northern District of California, Case No. C-02-O1854 VRW; United States Court of Appeals for the Ninth Circuit, Case No. 02-16619.

     This action was filed in state court on March 11, 2002 against us, Dynegy, Dynegy Power Marketing, Inc., Xcel Energy, West Coast Power and four of West Coast Power’s operating subsidiaries. Through our subsidiary, NRG West Coast LLC, we are a 50 percent beneficial owner with Dynegy of West Coast Power, which owns, operates, and markets the output of four California plants. Dynegy and its affiliates and subsidiaries are responsible for gas procurement and marketing and trading activities on behalf of West Coast Power. The Complaint alleges that the defendants violated California Business & Professions Code § 17200 by selling ancillary services to the Cal ISO, and subsequently selling the same capacity into the spot market. The California Attorney General seeks injunctive relief as well as restitution, disgorgement and civil penalties.

     On April 17, 2002, the defendants removed the case to the United States District Court in San Francisco. Thereafter, the case was transferred to Judge Vaughn Walker, who is also presiding over various other “ancillary services” cases brought by the California Attorney General against other participants in the California market, as well as other lawsuits brought by the Attorney General against these other market participants. We have tolling agreements in place with the Attorney General with respect to such other proposed claims against us.

     The Attorney General filed motions to remand, which the defendants opposed in July of 2002. In an Order filed in early September 2002, Judge Walker denied the remand motions. The Attorney General has appealed that decision to the United States Court of Appeal for the Ninth Circuit, and the appeal is pending. The Attorney General also sought a stay of proceedings in the district court pending the appeal, and this request was also denied. In a lengthy opinion filed March 25, 2003, Judge Walker dismissed the Attorney General’s action against Dynegy and us with prejudice, finding it was barred by the filed-rate doctrine and preempted by federal law. The Attorney General filed a Notice of Appeal, and the appeal was argued in August 2003 and also is pending.

     Public Utility District of Snohomish County v. Dynegy Power Marketing, Inc et al.,Case No. 02-CV-1993 RHW, United States District Court, Southern District of California (part of MDL 1405).

     This action was filed against us, Dynegy, Xcel Energy and several other market participants in the United States District Court in Los Angeles on July 15, 2002. The complaint alleges violations of the California Business & Professions Code § 16720 (the Cartwright Act) and Business & Professions Code § 17200. The basic claims are price fixing and restriction of supply, and other market “gaming” activities.

     The action was transferred from Los Angeles to the United States District Court in San Diego and was made a part of the Multi-District Litigation proceeding described below. All defendants filed motions to dismiss and to strike in the fall of 2002. In an Order dated January 6, 2003, Judge Robert Whaley, a federal judge from Spokane sitting in the United States District Court in San Diego, pursuant to the Order of the Multi-District Litigation Panel, granted the motions to dismiss on the grounds of federal preemption and filed- rate doctrine. The plaintiffs have filed a notice of appeal, and the appeal is pending.

     In re: Wholesale Electricity Antitrust Litigation,MDL 1405, United States District Court, Southern District of California, pending before Judge Robert H. Whaley. The cases included in this proceeding are as follows:

     Pamela R Gordon, on Behalf of Herself and All Others Similarly Situated v Reliant Energy, Inc. et al.,Case No. 758487, Superior Court of the State of California, County of San Diego (filed on November 27, 2000).

     Ruth Hendricks, On Behalf of Herself and All Others Similarly Situated and On Behalf of the General Public v. Dynegy Power Marketing, Inc. et al.,Case No. 758565, Superior Court of the State of California, County of San Diego (filed November 29, 2000).

     The People of the State of California, by and through San Francisco City Attorney Louise H. Renne v. Dynegy Power Marketing, Inc. et al.,Case No. 318189, Superior Court of California, San Francisco County (filed January 18, 2001).

     Pier 23 Restaurant, A California Partnership, On Behalf of Itself and All Others Similarly Situated v PG&E Energy Trading et al.,Case No. 318343, Superior Court of California, San Francisco County (filed January 24, 2001).

     Sweetwater Authority, et al. v. Dynegy, Inc. et al.,Case No. 760743, Superior Court of California, County of San Diego (filed January 16, 2001).

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     Cruz M Bustamante, individually, and Barbara Matthews, individually, and on behalf of the general public and as a representative taxpayer suit, v. Dynegy Inc. et al., inclusive.Case No. BC249705, Superior Court of California, Los Angeles County (filed May 2, 2001).

     All of West Coast Power’s operating subsidiaries are defendants in at least one of these six consolidated cases, which were all filed in late 2000 and 2001 in various state courts throughout California. They allege unfair competition, market manipulation and price fixing. All the cases were removed to the appropriate United States District Courts, and were thereafter made the subject of a petition to the Multi-District Litigation Panel (Case No. MDL 1405). The cases were ultimately assigned to Judge Whaley. Judge Whaley entered an order in 2001 remanding the cases to state court, and thereafter the cases were coordinated pursuant to state court coordination proceedings before a single judge in San Diego Superior Court. Thereafter, Reliant Energy and Duke Energy filed cross-complaints naming various Canadian, Mexican and United States government entities. Some of these defendants once again removed the cases to federal court, where they were again assigned to Judge Whaley. The defendants filed motions to dismiss and to strike under the filed-rate and federal preemption theories, and the plaintiffs challenged the district court’s jurisdiction and sought to have the cases remanded to state court. In December 2002, Judge Whaley issued an opinion finding that federal jurisdiction was absent in the district court, and remanding the cases to state court. Duke Energy and Reliant Energy then filed a notice of appeal with the Ninth Circuit, and also sought a stay of the remand pending appeal. The stay request was denied by Judge Whaley. On February 20, 2003, however, the Ninth Circuit stayed the remand order and accepted jurisdiction to hear the appeal of Reliant Energy and Duke Energy on the remand order. We anticipate that filed-rate/federal preemption pleading challenges will be renewed once the remand appeal is decided.

     “Northern California”cases against various market participants, not including us (part of MDL 1405). These include theMillar, Pastorino, RDJ Farms, Century Theatres, EI Super Burrito, Leo’s, J&M Karsant,andBronco Don cases. We were not named in any of these cases, but in virtually all of them, either West Coast Power or one or more of its operating subsidiaries is named as a defendant. These cases all allege violation of Business & Professions Code § 17200, and are similar to the various allegations made by the Attorney General. Dynegy is named as a defendant in all these actions, and Dynegy’s outside counsel is representing both Dynegy and the West Coast Power entities in each of these cases. These cases all were removed to federal court, made part of the Multi-District Litigation, and denied remand to state court. In late August 2003, Judge Whaley granted the defendants’ motions to dismiss in these various cases, which are now the subject of the plaintiffs’ appeal to the Ninth Circuit Court of Appeals.

     Bustamante v. McGraw-Hill Companies, Inc., et al.,No. BC 235598, California Superior Court, Los Angeles County.

     This putative class action lawsuit was filed on November 20, 2002. The complaint generally alleges that the defendants attempted to manipulate gas indexes by reporting false and fraudulent trades. Named defendants in the suit include numerous industry participants unrelated to us, as well as the operating subsidiaries established by West Coast Power for each of its four plants: El Segundo Power, LLC; Long Beach Generation, LLC; Cabrillo Power I LLC; and Cabrillo Power II LLC. The complaint seeks restitution and disgorgement of “ill-gotten gains,” civil fines, compensatory and punitive damages, attorneys’ fees and declaratory and injunctive relief. The plaintiff filed an amended complaint in 2003.

     Jerry Egger, et al. v. Dynegy, Inc., et al.,Case No. 809822, Superior Court of California, San Diego County (filed May 1, 2003). This class action complaint alleges violations of California’s Antitrust Law, Business and Professional Code, and unlawful and unfair business practices. The named defendants include “West Coast Power, Cabrillo II, El Segundo Power, Long Beach Generation.” We are not named. This case now has been removed to the United States District Court, and the defendants have moved to have this case included as Multi-District Litigation along with the above referenced cases before Judge Walker. Plaintiffs have filed a motion to remand to state court, which was heard on February 19, 2004. At the hearing, the court decided to stay the case pending a decision from the Ninth Circuit Court of Appeals in the Pastorino appeal, referenced above.

     Texas-Ohio Energy, Inc., on behalf of Itself and all others similarly situated v. Dynegy, Inc. Holding Co., West Coast Power, LLC, et al.,Case No. CIV.S-03-2346 DFL GGH. This putative class action was filed on November 10, 2003, in the United States District Court for the Eastern District of California. The complaint alleges violations of the federal Sherman and Clayton Acts and California’s Cartwright Act and Business and Professions Code. In addition to naming West Coast Power and Dynegy, Inc. Holding Co., the complaint names numerous industry participants, as well as “unnamed co-conspirators.” The complaint alleges that defendants conspired to manipulate the spot price and basis differential of natural gas with respect to the California market, allegedly enabling defendants to reap exorbitant and illicit profits by gouging natural gas purchasers. Specifically, the complaint alleges that defendants and their co-conspirators employed a variety of false reporting techniques to manipulate the published natural gas price indices. The complaint seeks unspecified amounts of damages, including a trebling of plaintiff’s and the putative class’s actual damages. We are unable at this time to predict the outcome of this dispute or the ultimate liability, if any, of West Coast Power.

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California Investigations

FERC — California Market Manipulation

     The Federal Energy Regulatory Commission has had an ongoing “Investigation of Potential Manipulation of Electric and Natural Gas Prices,” involving hundreds of parties (including our affiliate, West Coast Power) and substantial discovery. In June 2001, FERC initiated proceedings related to California’s demand for $8.9 billion in refunds from power sellers who allegedly inflated wholesale prices during the energy crisis. Hearings were conducted before an administrative law judge, who issued an opinion in late 2002. The administrative law judge stated that after assessing a refund of $1.8 billion for “unjust and unreasonable” power prices between October 2, 2000 and June 20, 2001, power suppliers were owed $1.2 billion because the State was holding funds owed to suppliers.

     In August 2002, the United States Circuit Court of Appeals for the Ninth Circuit granted a request by the Electricity Oversight Board, the California Public Utilities Commission and others, to seek out and introduce to FERC additional evidence of market manipulation by wholesale sellers. This decision resulted in FERC ordering an additional 100 days of discovery in the refund proceeding, and also allowing the relevant time period for potential refund liability to extend back an additional nine months, to January 1, 2000.

     On December 12, 2002, FERC Administrative Law Judge Birchman issued a Certification of Proposed Findings on California Refund Liability in Docket No. EL00-95-045 et al., which determined the method for calculating the mitigated energy market clearing price during each hour of the refund period. On March 26, 2003, FERC issued an Order on Proposed Findings on Refund Liability, or “Refund Order,” in Docket No. EL00-95-045, adopting, in part, and modifying, in part, the Proposed Findings issued by Judge Birchman on December 12, 2002. In the Refund Order, FERC adopted the refund methodology in the Staff Final Report on Price Manipulation in Western Markets issued contemporaneously with the Refund Order in Docket No. PA02-2-000. This refund calculation methodology makes certain changes to Judge Birchman’s methodology, because of FERC Staff’s findings of manipulation in gas index prices. This could materially increase the estimated refund liability. The Refund Order directed generators wanting to recover any fuel costs above the mitigated market clearing price during the refund period to submit cost information justifying such recovery within 40 days of the issuance of the Refund Order, which West Coast Power did.

     Dynegy, we and the West Coast Power entities have been engaged in extensive settlement negotiations with FERC Staff; the People of the State of Californiaex rel. Bill Lockyer, Attorney General; the California Public Utility Commission (“CPUC”) staff; the California Department of Water Resources acting through its Electric Power Fund, the California Electricity Oversight Board; PG&E; Southern California Edison Company; and San Diego Gas and Electric Company, and the parties have now reached a comprehensive settlement.

     As part of the settlement agreement, which is subject to final documentation and approval by FERC and the CPUC, West Coast Power will place into escrow for distribution to various California energy consumers a total of $22.5 million, which includes the $3 million settlement with FERC announced on Jan. 20, 2004. In addition, West Coast Power will forego: (1) Past due receivables from the California Independent System Operator (ISO) and the California Power Exchange related to the settlement period; and (2) natural gas cost recovery claims against the settling parties related to the settlement period. In exchange, the various California settling parties will forego: (1) All claims relating to refunds or other monetary damages for sales of electricity during the settlement period; (2) claims alleging that West Coast Power received unjust or unreasonable rates for the sale of electricity during the settlement period; and (3) FERC will dismiss numerous investigations respecting market transactions.

     Since the inception of the disputes related to energy sales in California at the end of 2000, West Coast Power has established significant reserves on its balance sheet. As a result, we will not incur any further loss associated with this settlement. We will pay no cash from corporate funds, nor will the settlement have any direct impact on the Company’s profit and loss statement.

Other FERC Proceedings

     There are a number of additional, related proceedings in which West Coast Power entities are parties, which are either pending before FERC or on appeal from FERC to various United States Courts of Appeal. These cases involve, among other things, a FERC-established price mitigation plan determining maximum rates for wholesale power transactions in certain spot markets, and the enforceability of, and obligations under, various contracts with, among others, the California ISO and the State of California and certain of its agencies and departments.

CFTC — Dynegy/West Coast Power Natural Gas Futures Index Manipulation

     On December 18, 2002, a Dynegy subsidiary, Dynegy Marketing & Trade, or “DMT”, and West Coast Power, collectively “the Respondents,” entered into a consent Offer of Settlement and Order, “the Consent Order”, with the Commodity Futures Trading Commission, or “CFTC.” The action was captioned In re Dynegy Marketing & Trade and West Coast Power LLC, CFTC Docket No. 03-03. The CFTC asserted various violations of the Commodity Exchange Act, as well as CFTC regulations.

     The CFTC alleged in the Consent Order that DMT natural gas traders reported false natural gas trading information, including price and volume information, to certain industry publications that establish and publish indexes for natural gas prices. The CFTC alleged that DMT submitted the false information in an attempt to manipulate the indexes for DMT’s benefit. The CFTC further alleged that DMT traders directed other Dynegy personnel to report each of the same false trades in the name of West Coast Power, as counterparty,

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in an effort to lend credence to the trades’ validity. The Respondents to the Consent Order did not admit or deny the allegations or findings made by the CFTC, but agreed to an Offer of Settlement, and agreed to pay a civil monetary fine of $5 million. The Respondents also agreed to undertakings regarding further cooperation with the CFTC and public statements concerning the Consent Order. Dynegy agreed to pay and be entirely responsible for the $5 million fine imposed by the CFTC.

U.S. Attorney — Houston

     The U.S. Attorney indicted two fired Dynegy traders in connection with the index reporting scheme, and is reportedly investigating other Dynegy activity and employees.

U.S. Attorney — San Francisco

     According to press reports, the U.S. Attorney in San Francisco assembled an “energy crisis” task force. While Dynegy received a grand jury subpoena in November 2002, the scope and targets of this investigation are unknown to us. We did not receive a subpoena.

California State Senate Select Committee

     This Committee, chaired by Senator Dunn, subpoenaed records from us during the Summer of 2001. We produced about 5,000 pages of documents; Dynegy produced a much larger volume of documents. The Committee has apparently concluded its activities without issuing any reports or findings.

CPUC

     The CPUC continues to request data and documents in several settings. First, it is one of the parties in the FERC proceeding mentioned above. Second, inspectors have visited West Coast Power plants, usually unannounced and usually immediately following an unplanned outage. They have demanded documentation concerning the reason for the outage. Third, the CPUC has demanded documents to allow it to prepare “reports,” one of which was issued in the fall of 2002, and another of which was issued January 30, 2003. The FERC’s above-referenced March 26 Refund Order undercut the accuracy and reliability of these CPUC reports. Dynegy has made extensive productions to the CPUC of plant-related materials as well as trading data.

California Attorney General

     In addition to the litigation it has undertaken described above, the California Attorney General has undertaken an investigation entitled “In the Matter of the Investigation of Possibly Unlawful, Unfair, or Anti-Competitive Behavior Affecting Electricity Prices in California.” In this connection, the Attorney General issued subpoenas to Dynegy, served interrogatories on Dynegy and us, and informally requested documents and interviews from Dynegy and Dynegy employees as well as us and our employees. We responded to the interrogatories in the summer of 2002, with the final set of responses being served on September 3, 2002. We also produced a large volume of documentation relating to the West Coast Power plants. In addition, our employees in California sat for informal interviews with representatives of the Attorney General’s office. Dynegy employees also were interviewed.

     On November 21, 2003, in conjunction with confirmation of the NRG plan of reorganization, we reached an agreement with the Attorney General and the State of California, generally, whereby for purposes of distributions, if any, to be made to the State of California under the NRG plan of reorganization, the liquidated amount of any and all allowed claims shall not exceed $1.35 billion in the aggregate. The agreement neither affects our right to object to these claims on any and all grounds nor admits any liability whatsoever. We further agreed to waive any objection to the liquidation of these claims in a non-bankruptcy forum having proper jurisdiction.

     Although any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the above-referenced private actions and various investigations cannot be made at this time, we note that the Gordon complaint alleges that the defendants, collectively, overcharged California ratepayers during 2000 by $4.0 billion. We know of no evidence implicating us in the various private plaintiffs’ allegations of collusion. We cannot predict the outcome of these cases and investigations at this time.

Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Case No. 03-1449

     On December 19, 2003 the Electricity Consumers Resource Council, or “ECRC”, appealed to the United States Court of Appeals for the District of Columbia Circuit a recent decision by FERC approving the implementation of a demand curve for the New York

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installed capacity, or “ICAP”, market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the Federal Power Act because it constitutes unreasonable ratemaking. We are a party to this appeal and will contest ECRC’s assertions, but at this time cannot assess what the eventual outcome will be.

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

     This matter involves a claim by CL&P for recovery of amounts it claims are owing for congestion charges under the terms of a SOS contract between the parties, dated October 29, 1999. CL&P has served and filed its motion for summary judgment to which PMI filed a response on March 21, 2003. CL&P has withheld approximately $30 million from amounts owed to PMI, claiming that it has the right to offset those amounts under the contract. 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 previous 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 and PMI intends to supplement the record on the pending summary judgment motion. PMI cannot estimate at this time the likelihood of an unfavorable outcome in this matter.

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

     This matter involves a dispute between CL&P and PMI concerning which party is responsible, under the terms of the October 29, 1999 SOS contract, for costs related to congestion and losses associated with the implementation of standard market design, or “SMD-Related Costs.” CL&P has withheld, in addition to the $30 million discussed above, approximately $79 million from amounts owed to PMI, claiming that it is entitled under the contract to offset those additional amounts for SMD-Related Costs. The parties have now reached a settlement whereby CL&P will pay PMI $38.4 million plus interest, and subject to adjustments and true-ups upon final approval by FERC. The settlement agreement was filed with FERC on March 3, 2004.

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, the New York Department of Environmental Conservation, or “DEC”, sued Niagara Mohawk Power Corporation, or “NiMo”, and us in federal court in New York. The complaint asserted that projects undertaken at our 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, we filed a motion to dismiss. On March 27, 2003, the court dismissed the complaint against us 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 December 31, 2003, the trial court granted the state’s motion to amend the complaint to again sue us and various affiliates in this same action in the federal court in New York, asserting against us violations of operating permits and deficient operating permits at the Huntley and Dunkirk plants. If the case ultimately is litigated to an unfavorable outcome that could not be addressed otherwise, we have 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. We also could be found responsible for payment of certain penalties and fines.

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

     We have asserted that NiMo is obligated to indemnify us 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 us under the asset sales agreement. We have pending a summary judgment motion on our entitlement to be reimbursed by NiMo for the attorneys’ fees we have incurred in the enforcement action.

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Huntley Power LLC

     On April 30, 2003, the Huntley Station submitted a self-disclosure letter to the 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 three 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. Huntley Power LLC has met with the DEC to discuss the circumstances surrounding the event and the appropriate means of resolving the matter. Huntley Power LLC 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, NRG Dunkirk Operations, Inc., Huntley Power LLC, NRG Huntley Operations, Inc., Oswego Power LLC and NRG Oswego Operations, Inc., Supreme Court, Erie County, Index No. 1-2000-8681 — Station Service Dispute ;

     On October 2, 2000, plaintiff Niagara Mohawk Power Corporation, or “NiMo,” commenced this action against us 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. NiMo claims that we have 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, we 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 our Huntley and Oswego subsidiaries, both of which cases assert the same claims and legal theories for failure to pay retail tariffs for utility services at those plants.

     On October 8, 2002, a Stipulation and Order was filed in the Erie County Clerk’s Office staying this action pending submission to FERC of some or all of the disputes in the action. We 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 NiMo at FERC, similarly asserting that NiMo 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 it supported and agreed with each position taken by our facilities. In short, the staff argued that our facilities: (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. We are presently awaiting a ruling by FERC. At this stage of the proceedings, we cannot estimate the likelihood of success on this action. As noted above, the cumulative potential loss could exceed $35 million.

In the Matter of Louisiana Generating, LLC, Adversary Proceeding No. 2002-1095 1-EQ on the docket of the Louisiana Division of Administrative Law

     During 2000, DEQ issued a Part 70 Air Permit modification to Louisiana Generating to construct and operate two 240 MW natural gas-fired turbines. The Part 70 Air Permit set emissions limits for the criteria air pollutants, including NO(x), based on the application of Best Available Control Technology, or “BACT.” The BACT limitation for NO(x) was based on the guarantees of the manufacturer, Siemens-Westinghouse. Louisiana Generating sought an interim emissions limit to allow Siemens-Westinghouse time to install

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additional control equipment. To establish the interim limit, DEQ issued a Compliance Order and Notice of Potential Penalty, No. AE-CN-02-0022, on September 8, 2002, which is, in part, subject to the above-referenced administrative hearing. DEQ alleged that Louisiana Generating did not meet its NO(x) emissions limit on certain days, did not conduct all opacity monitoring and did not complete all record keeping and certification requirements. Louisiana Generating intends to vigorously defend certain claims and any future penalty assessment, while also seeking an amendment of its limit for NO(x). An initial status conference was held with the Administrative Law Judge and quarterly reports are being submitted to that judge to describe progress, including settlement and amendment of the limit. In late February 2004, we timely submitted to the DEQ an amended BACT analysis and amended Prevention of Significant Deterioration and Title V permit application to amend the NO(x) limit. In addition, Louisiana Generating may assert breach of warranty claims against the manufacturer. With respect to the administrative action described above, at this time we are unable to predict the eventual outcome of this matter or the potential loss contingencies, if any, to which we may be subject.

NRG Sterlington Power, LLC

     During 2002, NRG Sterlington conducted a review of the Sterlington Power Facility’s Part 70 Air Permit obtained by the facility’s former owner and operator, Koch Power, Inc. Koch had outlined a plan to install eight 25 MW capacity turbines to reach a 200 MW capacity limit in the permit. Due to the inability of several units to reach their nameplate capacity, Koch determined that it would need additional units to reach the electric output target. In August 2000, NRG Sterlington acquired the remaining interests in the facility not originally held on a passive basis and sought the transfer of the Part 70 Air Permit along with a modification to incorporate two 17.5 MW turbines installed by Koch and to increase the total number of turbines to ten. The permit modification was issued February 13, 2002. During further review, NRG Sterlington determined that a ninth unit had been installed prior to issuance of the permit modification. In keeping with its environmental policy, it disclosed this matter to DEQ in April, 2002. NRG Sterlington provided to DEQ additional information during July 2002. A Consolidated Compliance Order & Notice of Potential Penalty, No. AE-CN-01-0393, was issued by DEQ on September 10, 2003, wherein DEQ formally alleged that NRG Sterlington did not complete all certification requirements, and installed a ninth unit prior to issuance of its permit modification. We met with DEQ on November 19, 2003 to discuss mitigating circumstances and a settlement has been agreed to between the parties. Under the settlement agreement, without admitting any liability, NRG Sterlington has agreed to pay DEQ the sum of $4,500. The agreement is subject to a public comment period and review by the Louisiana attorney general.

United States Environmental Protection Agency Request for Information under Section 114 of the Clean Air Act

     On January 27, 2004, Louisiana Generating, LLC and Big Cajun II received a request for information under Section 114 of the Clean Air Act from the United States Environmental Protection Agency, or “EPA”, seeking information primarily relating to physical changes made at Big Cajun II in 1994 and 1995 by the predecessor owner of that facility. Louisiana Generating, LLC and Big Cajun II are responding to the EPA request in an appropriate manner. At the present time, we cannot predict the probable outcome in this matter.

Itiquira Energetica, S.A.

     Our indirectly controlled Brazilian project company, Itiquira Energetica S.A., the owner of a 156 MW hydro project in Brazil, is currently in arbitration with the former EPC contractor for the project, Inepar Industria e Construcoes, or “Inepar.” The dispute was commenced by Itiquira in September of 2002 and pertains to certain matters arising under the former EPC contract. Itiquira principally asserts that Inepar breached the contract and caused damages to Itiquira by (i) failing to meet milestones for substantial completion; (ii) failing to provide adequate resources to meet such milestones; (iii) failing to pay subcontractors amounts due; and (iv) being insolvent. Itiquira’s arbitration claim is for approximately U.S. $40 million. Inepar has asserted in the arbitration that Itiquira breached the contact and caused damages to Inepar by failing to recognize events of force majeure as grounds for excused delay and extensions of scope of services and material under the contract. Inepar’s damage claim is for approximately U.S. $10 million. The parties submitted their respective statements of claims, counterclaims and responses, and a preliminary arbitration hearing was held on March 21, 2003. In lieu of taking expert testimony at hearing, the court of arbitration ordered an expert investigation process to cover technical and accounting

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issues. The final report from the expert investigation process has been delivered to the court of arbitration and we have until May 22, 2004, to submit a response, which we intend to do. After reviewing the final report, the court of arbitration may, if it deems it necessary, require expert testimony on technical and accounting issues, which we anticipate would commence in June, 2004. We expect the arbitration panel to issue its decision no later than July 31, 2004. We cannot estimate the likelihood of an unfavorable outcome in this dispute.

CFTC Trading Inquiry

     On June 17, 2002, the CFTC served Xcel Energy, on behalf of its affiliates, which then included us and PMI, with a subpoena requesting certain information regarding “round trip” or “wash” trading and general trading practices in its investigation of several energy trading companies. The CFTC now appears focused on possible efforts by traders to submit false reports to gas index publications in an attempt to manipulate the index. In January, 2004, the CFTC and Xcel Energy’s subsidiary e prime, inc., reached a settlement in connection with this investigation, which included the payment of a $16 million fine and the entry of a cease and desist order. Other industry participants that have settled with the CFTC have paid fines of between $1 million and $30 million and have agreed to the terms of cease and desist orders. The CFTC has requested additional related information from us and has subpoenaed to appear for testimony a number of our present and former employees. We have sought to cooperate with the CFTC and have submitted materials responsive to the CFTC’s requests, while vigorously denying that we engaged in any improper conduct. We have recently engaged in settlement discussions with the agency. We cannot at this time predict the outcome or financial impact of this investigation.

General Electric Company and Siemens Westinghouse Turbine Purchase Disputes

     We and/or our affiliates have entered into several turbine purchase agreements with affiliates of General Electric Company or “GE” and Siemens Westinghouse Power Corporation, or “Siemens,” GE and Siemens have notified us that we are in default under certain of those contracts, terminated such contracts, and demanded that we pay the termination fees set forth in such contracts. GE’s claim amounts to $120 million and Siemens’ approximately $45 million in cumulative termination charges. Most of these disputes fall within the NRG plan of reorganization and are subject to our disputed claims reserves, discussed above. We cannot estimate the likelihood of unfavorable outcomes in these disputes.

Additional Litigation

     In addition to the foregoing, we are parties to other litigation or legal proceedings, which may or may not be material. There can be no assurance that the outcome of such matters will not have a material adverse effect on our business, financial condition or results of operations.

Disputed Claims Reserve

     As part of the NRG plan of reorganization, we have funded a disputed claims reserve for the satisfaction of certain general unsecured claims that were disputed claims as of the effective date of the plan. Under the terms of the plan, to the extent such claims are resolved now that we have emerged from bankruptcy, the claimants will be paid from the reserve on the same basis as if they had been paid out in the bankruptcy. That means that their allowed claims will be reduced to the same recovery percentage as other creditors would have received and will be paid in pro rata distributions of cash and common stock. We believe we have funded the disputed claims reserve at a sufficient level to settle the remaining unresolved proofs of claim we received during the bankruptcy proceedings. However, to the extent the aggregate amount of these payouts of disputed claims ultimately exceeds the amount of the funded claim reserve, we are obligated to provide additional cash and common stock to the disputed claims reserve. We will continue to monitor our obligation as the disputed claims are settled. If excess funds remain in the disputed claims reserve after payment of all obligations, such amounts will be reallocated to the Creditor Pool. We have provided our common stock and cash contribution to an escrow agent to complete the distribution and settlement process. Since we have surrendered control over the common stock and cash provided to the disputed claims reserve, we recognized the issuance of the common stock as of December 6, 2003 and removed the cash amounts from our balance sheet. Similarly, we have removed the obligations relevant to the claims from our balance sheet when the common stock was issued and cash contributed.

     In conjunction with confirmation of the NRG plan of reorganization, we reached an agreement with the Attorney General and the State of California that limits the potential maximum amount of its claims, if any. Under the NRG plan of reorganization, the liquidated amount of any allowed claims shall not exceed $1.35 billion in total. The agreement neither affects our right to object to these claims on any grounds nor admits any liability. We further agreed to waive any objection to the liquidation of these claims in a non-bankruptcy forum having proper jurisdiction. Although we cannot at this time make any evaluation of the likelihood of an unfavorable outcome or an estimate of the amount or range of potential loss in the private actions and various investigations, we know of no evidence implicating us in the various private plaintiffs’ allegations of collusion. We cannot predict the outcome of these cases and investigations at this time.

Note 18 — Guarantees

     In November 2002, the FASB issued FASB Interpretation No. 45,“Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.”The initial recognition and initial measurement provisions of this interpretation are applicable on a prospective basis to guarantees issued or modified after December 31, 2002, irrespective of the

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guarantor’s fiscal year-end. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. The interpretation addresses the disclosures to be made by a guarantor in its interim and annual financial statements about its obligations under guarantees. The interpretation also clarifies the requirements related to the recognition of a liability by a guarantor at the inception of the guarantee for the obligations the guarantor has undertaken in issuing the guarantee.

     In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly we applied the provisions of FIN 45 to all of those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception.

     We are directly liable for the obligations of certain of our project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and 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 our generation facilities in the United States, we may be required to guarantee a portion of the obligations of certain of our subsidiaries.

As of March 31, 2004, our obligations pursuant to our guarantees of the performance, equity and indebtedness obligations of our subsidiaries were as follows(includes only quantifiable amounts):

Description	March 31, 2004
	(In thousands)
Guarantees of subsidiaries	$	556,654
Guarantees of NRG PMI obligations		56,266
Total	$	612,920

     As of March 31, 2004, the nature and details of our guarantees were as follows:

	Maximum Amount
	(March 31, 2004)
Project or Subsidiary	(In thousands)		Nature of Guarantee	Expiration	Triggering Event
Astoria/Arthur Kill	Indeterminate		Performance Under Asset Purchase Agreement	None stated	Non-performance
Cobee (1)	$	50,000	Guarantee of Obligations Under the Sale and Purchase Agreement	April 27, 2008	Non-performance or non-payment
Elk River		11,990	Executory Contract	Undetermined	Non-payment
Flinders		8,120	Fund Superannuation (Pension) Reserve	September 8, 2012	Credit agreement default
Flinders		53,599	Debt Service Reserve Guaranty	September 8, 2012	Credit agreement default
Flinders		63,219	Plant Removal and Site Remediation Obligation	Undetermined	Non-performance
Flinders		76,570	Guaranty of Employee Separation Benefits	None stated	Non-payment
Flinders	Indeterminate		Indemnification of Government Entity for Payment for Power and Fuel	Fourth quarter 2018	Non-payment
Flinders		248,236	Guaranty of Obligation to Purchase Gas	None stated	Non-payment
Gladstone		24,986	Payment of Penalties in the Event of an Extraordinary Operational Breach	None stated	Non-performance
Gladstone	Indeterminate		Performance Obligations under Credit Agreement	March 31, 2009	Non-performance
McClain		1,015	Obligation to Fund Debt Service Reserve Shortfall	None stated	Non-payment
MIBRAG		8,393	Guarantee of Share Purchase Agreement	None stated	Non-performance
Newport		7,500	Executory Contract	Undetermined	Non-payment
Other		2,282	Various	Various	Various
PMI		56,266	Guarantee on behalf of NRG Power Marketing Inc. for various Counter-Parties	Various	Non-performance
SLAP I.	Indeterminate		Subscription Commitment Guaranty	None stated	Non-performance
West Coast LLC		744	Guaranty of Environmental Cleanup Costs	None stated	Non-performance
West Coast LLC	Indeterminate		Continuing Obligations Under Asset Sales Agreement and Related Contracts	None stated	Non-performance

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Recourse provisions for each of the guarantees above are to the extent of their respective liability. No assets are held as collateral for any of the above guarantees.

As of April 7, 2004, we are obligated under a guarantee we entered into with respect to the sale of our interest in the Loy Yang A project. Under this guarantee, our maximum exposure is $27.8 million (USD) and is contingent upon the performance of our subsidiary under the Share Sale Agreement. This obligation will terminate on April 7, 2011.

(1) Effective with the sale of Cobee, which occurred on April 27, 2004, our guarantee obligation with respect to that project was reduced to $12.5 million, per the Purchase and Sale Agreement executed on March 18, 2004.

Note 19 — Benefit Plans and Other Postretirement Benefits

Reorganized NRG

     Substantially all of our employees participate in defined benefit pension plans. We have initiated a new NRG Energy noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. In addition, we provide postretirement health and welfare benefits (health care and death benefits) for certain groups of our employees. Generally, these are groups that were acquired in recent years and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements.

NRG Pension and Postretirement Medical Plans

Components of Net Periodic Benefit Cost

     The net annual periodic pension cost related to all of our plans, include the following components:

	Pension Benefits				Other Benefits
	Predecessor Company		Reorganized NRG		Predecessor Company			Reorganized NRG
	For the Three Months		For the Three Months		For the Three Months			For the Three Months
	Ended March 31, 2003		Ended March 31, 2004		Ended March 31, 2003			Ended March 31, 2004
			(In thousands)
Service cost benefits earned	$	—	$	2,950	$	334		$	465
Interest cost on benefit obligation		—		738		525			630
Amortization of prior service cost		—		—		(6	)		—
Expected return on plan assets		—		—		—			—
Recognized actuarial (gain)/loss		—		—		48			—
Net periodic benefit cost	$	—	$	3,688	$	901		$	1,095

2003 Medicare Legislation

     On December 8, 2003, President Bush signed into law the Medicare Prescription Drug Improvement and Modernization Act of 2003, or “the Act”. The Act expanded Medicare to include for the first time, coverage for prescription drugs. This coverage is generally effective January 1, 2006. The execution of this new legislation had no significant impact on our statement of financial position or results of operation as of March 31, 2004. Any future impact will be recognized as incurred. Specific authoritative guidance on the accounting for the federal subsidy is pending.

Note 20 — Creditor Pool and Other Settlements

     A principal component of our plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash (and, under certain circumstances, its stock) in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of our plan of reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and us and/or our creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from us and our creditors, except for a limited number of creditors who have preserved their claims as set forth in the confirmation order entered on November 24, 2003. On February 20, 2004, we received $288 million from Xcel Energy. On April 30, 2004 we received $328.5 million from Xcel Energy as part of the third settlement payment. The remainder of the third settlement payment, $23.5 million, is expected from Xcel Energy on May 30, 2004. We used the proceeds from the Xcel Energy settlement to reduce our creditor pool obligation. As of December 31, 2003 and March 31, 2004 the balance of our creditor pool obligation was $540.0 million and $377.0 million, respectively. On February 20, 2004 and April 30, 2004 we made payments of $163.0 million and $328.5 million, respectively. In addition, our other bankruptcy settlement obligation as of December 31, 2003 and March 31, 2004 was $220.0 million and $219.5 million, respectively. This obligation relates to the allowed claims pending against our Audrain and Pike facilities. The net change in the balance of $219.5 million relates to an agreement whereby we are entitled to reimbursement of certain costs incurred while we are maintaining these facilities in anticipation of their sale whereupon any proceeds will be turned over to the creditors.

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

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

     NRG Energy, Inc. is a wholesale power generation 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 and internationally. We have a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels, which help us, mitigate risk. We intend to maximize operating income through the efficient procurement and management of fuel supplies and maintenance services, and the sale of energy, capacity and ancillary services into attractive spot, intermediate and long-term markets.

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     Our focus will continue to be on the operating performance of our entire portfolio and, in particular, on developing the assets in our core regions into integrated businesses well-suited to serving the requirements of the load-serving entities in our core markets. Power sales, fuel procurement and risk management will remain a key strategic element of these regional businesses contributing to our overall objective to optimize the operating income generated by all of our facilities within an appropriate risk and liquidity profile. Our business will involve the reinvestment of capital in our existing assets for reasons of life extension, repowering, expansion, environmental remediation, operating efficiency, greater fuel optionality or for alternative use, among other reasons. Our business also may involve select acquisitions intended to complement and enhance the commercial performance of the asset portfolios in our core regions.

     Industry Trends.In this “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” we will discuss its historical results of operations. During the past two years, the following factors, among others, may have negatively affected our results of operations:

• weak markets for electric energy, capacity and ancillary services in most U.S. markets, accentuated by an over-supply of newly constructed generation facilities;

• a narrowing of the “spark spread” (the difference between power prices and gas costs) in most regions of the United States in which we operate power generation facilities, offset by our coal-fired assets, which gain a competitive advantage when gas prices rise;

• mild weather during peak seasons in regions where we have significant merchant capacity; however, we benefited from cold weather in the Northeast region of the U.S. during January of 2004;

• 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 we have significant merchant capacity:

• regulatory and market frameworks in certain regions where we operate that prevent us from charging prices that will enable us to recover our operating costs and to earn acceptable returns on capital; however, we benefited from the FERC acceptance of certain RMR agreements subject to refund;

• the obligation through 2003 to perform under certain long-term contracts that were not profitable;

• physical, regulatory and market constraints on transmission facilities in certain regions that limit or prevent us from selling power generated by certain of our facilities; and

• changes and turnover in senior and middle management since June 2002 in connection with our restructuring.

     We expect that generally weak market conditions will continue for the foreseeable future in many U.S. markets. Historically, we have 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 our belief that in the long run market prices will support an adequate rate of return on the construction of new or re-powered 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 we could have significant impairments of our property, plant and equipment, which, in turn, could have a material adverse effect on our results of operations. Further, this could lead to our closing certain of our facilities resulting in additional economic losses and liabilities.

     Asset Sales.As part of our strategy, we plan to continue the selective divestment of certain assets. Since July 2002, we have sold or made arrangements to sell a number of assets and equity investments. In addition, we are continuing to market our interest in several remaining non-core assets.

     Discontinued Operations.We have classified certain business operations, and gains/losses recognized on sale, as discontinued operations for projects that were sold or have met the required criteria for such classification pending final disposition. Accounting regulations require that continuing operations be reported separately in the income statement from discontinued operations, and that any gain or loss on the disposition of any such business be reported along with the operating results of such business. Assets classified as “discontinued operations” on our balance sheet as of March 31, 2004 include McClain, Cobee and PERC. For the three months ended March 31, 2004, discontinued results of operations include our McClain, PERC and Cobee projects. All prior periods presented have been restated accordingly.

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     New Management.On October 21, 2003, we announced the appointment of David Crane as our new President and Chief Executive Officer, effective December 1, 2003. Before joining our company, Mr. Crane served as the Chief Executive Officer of London-based International Power PLC and has over 12 years of energy industry experience. On March 11, 2004 we announced the appointment of Robert Flexon as Executive Vice President and Chief Financial Officer, effective March 29, 2004. Before joining us, Mr. Flexon served as Vice President, Work Processes, Corporate Resources and Development at Hercules, Inc. In addition, we have filled several other senior and middle management positions over the last 12 months. Our board of directors is currently comprised of Mr. Crane and ten other independent individuals, three of whom have been designated by MatlinPatterson, a significant holder of NRG common stock.

     Independent Public Accountants; Audit Committee.PricewaterhouseCoopers LLP has been our independent auditors since 1995. On May 3, 2004, we announced that we initiated a search for a new independent auditor because PricewaterhouseCoopers LLP will not be standing for re-election as our independent auditor for the year ended December 31, 2004. Our new board of directors appointed an audit committee consisting entirely of independent directors in January 2004. Pursuant to its charter, the committee appoints, retains, oversees, evaluates, compensates and terminates on its sole authority our independent auditors and approves all audit engagements, including the scope, fees, and terms of each engagement. The audit committee’s oversight process is intended to ensure that we will continue to have high-quality, cost efficient independent auditing services.

     Fresh-Start Reporting.In connection with emergence from bankruptcy and completion of the restructuring, we adopted fresh-start reporting. Under fresh-start reporting, a new reporting entity is considered to be created and its reorganization value allocated to its assets based on their respective fair values in conformity with the purchase method of accounting for business combinations. Accordingly, our assets’ recorded values were adjusted to reflect their estimated fair values upon adoption of fresh-start reporting. Any portion of the reorganization value not attributable to specific assets is an indefinite-lived intangible asset referred to as “reorganization value in excess of value of identifiable assets” and reported as goodwill. We did not record any such amounts. As a result of adopting fresh-start reporting and emerging from bankruptcy, our historical financial information is not comparable to financial information for periods after our emergence from bankruptcy.

RESULTS OF OPERATIONS

Management’s discussion of our results of operations for the three months ended March 31, 2004 and for the three months ended March 31, 2003

     Upon our emergence from bankruptcy, we adopted the “fresh start” provisions of SOP 90-7, accordingly the Reorganized NRG balance sheet, statement of operations and statement of cash flows have not been prepared on a consistent basis with the Predecessor Company’s financial statements and are not comparable in certain respects to the financial statements prior to the application of Fresh Start, therefore, the Predecessor Company’s and the Reorganized NRG’s amounts are discussed separately for comparison and analysis purposes, herein.

Net (Loss)/Income

Reorganized NRG

     During the period January 1, 2004 through March 31, 2004, we recorded net income of $30.2 million, or $0.30 per share of common stock. Our results were favorably impacted by the cold weather in January in the Northeast region where heating degree days were 19% above normal. The unusually severe weather drove up gas prices, which reached, for a short period of time, $70/mmbtu in the New York City market. As gas prices generally set the marginal price of electricity in the Northern markets, our NEPOOL generating fleet and our Oswego facility, which operate on oil, generated more than expected. Additionally, our results benefited by locking in certain of our domestic coal costs.

Predecessor Company

     During the period January 1, 2003 through March 31, 2003, we recorded a net loss of $12.6 million. Our results were unfavorably impacted by continued losses on our CL&P standard offer service contract and increased costs related to our restructuring activities.

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Revenues from Majority Owned Operations

Reorganized NRG

     Revenues from majority owned operations of $621.2 million for the period January 1, 2004 through March 31, 2004, included $392.3 million of energy revenues, $150.4 million of capacity revenues, $46.4 million of alternative energy revenues, $5.6 million of O&M fees and $26.5 million of other revenues, which include financial and physical gas sales, and non-cash contract amortization resulting from fresh start accounting.

     Revenues from majority owned operations during the period January 1, 2004 through March 31, 2004, were driven primarily by our North American operations and to a lesser degree from our international operations, primarily Australia. Our domestic Northeast power generation operations significantly contributed to our energy revenues due to favorable market prices resulting from colder than normal weather and strong natural gas prices, which pushed up electricity prices. During January, cold weather in the Northeast resulted in increased gas prices. Gas prices generally set the marginal price of electricity allowing certain of our facilities which are not gas-fired, primarily our NEPOOL facilities and our Oswego facility, to operate at better then expected capacity levels thus resulting in strong merchant revenues. Regarding certain of our Connecticut facilities, we were able to capture increased energy market revenue from January 1 through January 16, 2004 due to prevailing weather conditions. From January 17, 2004 through March 31, 2004, most of our Connecticut facilities were compensated under cost based reliability must run, or “RMR” agreements. The most recently authorized RMR agreement entitles us to approximately $7.1 million of revenues per month. The rates under these agreements are not final and are subject to refund. In addition, we recorded capacity revenues of $150.4 million, which included compensation received under the RMR agreements. The majority of our capacity revenues come from our Northeast and South Central generating facilities. In the South Central region our long-term contracts generally provide for capacity payments. Our Australian operations were favorably impacted by strong market prices driven by gas restrictions in January which reduced the availability of gas fired generation for most of the quarter, record high temperatures in February and March, and favorable foreign exchange rate movements. Average power pool prices in Australia were in line with typical summer expectations. During this period we also experienced a favorable impact on our revenues due to the mark to market on certain of our derivative contracts. Our revenues were not adversely impacted by the CL&P standard offer contract, as in prior years, as the contract ended in December 2003. Our revenues during this period were adversely impacted by $16.5 million of non-cash amortization of the fair values of various executory contracts recorded on our balance sheet upon our adoption of the fresh start provisions of SOP 90-7 in December 2003.

Predecessor Company

     Revenues from majority owned operations of $519.6 million for the period January 1, 2003 through March 31, 2003, included $282.7 million of energy revenues, $146.1 million of capacity revenues, $42.5 million of alternative energy revenues, $3.8 million of O&M fees and $44.5 million of other revenues, which include financial and physical gas sales.

     Revenues from majority owned operations during the period January 1, 2003 through March 31, 2003, were driven primarily by our North American operations and to a lesser degree by our international operations, primarily Australia. Our domestic Northeast and South Central power generation operations significantly contributed to our revenues due primarily to favorable market prices resulting from strong fuel and electricity prices. Our Australian operations were favorably impacted by favorable foreign exchange rates. During this period we also experienced an unfavorable impact on our revenues due to continued losses on our CL&P standard offer contract and the mark to market on certain of our derivatives.

Cost of Majority-Owned Operations

Reorganized NRG

     Our cost of majority owned operations related to continuing operations for the period January 1, 2004 through March 31, 2004 was $392.4 million. Cost of majority owned operations, consists of the cost of energy (primarily fuel costs), labor, operating and maintenance costs and non-income based taxes. Given the strong demand for electricity in January 2004 in the Northeast region, our coal and oil plants were highly utilized. The utilization of our intermediate and peaking facilities exceed expectations resulting in higher fuel costs as these facilities are fueled by more expensive fuel oil and natural gas. Our cost structure was also unfavorably impacted by the non-cash amortization of the value of SO2 allowances recorded on our balance sheet resulting from fresh start accounting in the amount of $6.3 million.

Predecessor Company

     Our cost of majority owned operations related to continuing operations for the period January 1, 2003 through March 31, 2003 was $388.1 million. Cost of majority owned operations, consists of cost of energy (primarily fuel costs), labor, operating and maintenance costs and non-income based taxes. Cost of majority owned operations was unfavorably impacted by increased generation in the Northeast region, partially offset by a reduction in trading and hedging activity resulting from a reduction in our power marketing

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activities. Our international operations were unfavorably impacted due to an unfavorable movement in foreign exchange rates and continued mark-to-market of the Osborne contract at Flinders resulting from lower pool prices.

Depreciation and Amortization

Reorganized NRG

     Our depreciation and amortization expense related to continuing operations for the period January 1, 2004 through March 31, 2004 was $58.6 million. Depreciation and amortization consists primarily of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property. Upon our emergence from bankruptcy, we adopted the “Fresh Start” provisions of SOP 90-7 and were required to revalue our fixed assets to fair value and determine new remaining lives for such assets. Our fixed assets were written down substantially upon our emergence from bankruptcy. We also determined new remaining depreciable lives, which are on average, shorter then what we had previously used primarily due to the age and condition of our fixed assets. Accordingly, depreciation expense was favorably affected due to the overall reduction in the valuation of our depreciable fixed assets, and partially offset by the impact of shorter depreciable lives.

Predecessor Company

     Our depreciation and amortization expense related to continuing operations for the period January 1, 2003 through March 31, 2003 was $64.1 million. Depreciation and amortization consisted primarily of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property. During this period, depreciation expense was unfavorably impacted by the shortening of the depreciable lives of certain of our domestic power generation facilities located in the Northeast region and the impact of recently completed construction projects. The depreciable lives of certain of our Northeast facilities, primarily our Connecticut facilities, were shortened to reflect economic developments in that region.

General, Administrative and Development

Reorganized NRG

     Our general, administrative and development costs related to continuing operations for the period January 2004 through March 31, 2004 was $37.3 million or 6% of operating revenue. These costs are primarily comprised of corporate labor, insurance, and external professional support, such as; legal, financial advisors, audit fees, and board of directors fees.

Predecessor Company

     Our general, administrative and development cost related to continuing operations for the period January 1, 2003 through March 31, 2003 was $49.0 million or 9.4% of operating revenue. General, administrative and development cost was directly impacted by our efforts to stream line the operations through work force reduction efforts, closure of certain international offices and lower legal costs charged herein. In addition, an increase to our bad debt expense was recorded during this period.

Corporate Relocation Charges

     During March 2004, we announced plans to implement a new regional business strategy and structure. The new structure calls for a reorganized leadership team and a corporate headquarters relocation to West Windsor, New Jersey. The corporate relocation is intended to increase our effectiveness in serving our plants and employees as well as our external stakeholders such as regulators, customers and investors. This reorganization will streamline corporate headquarters staff as functions are shifted to the regions. The new corporate structure calls for a staff of approximately 140 employees. We currently have approximately 240 individuals at our Minneapolis headquarters. The transition of the corporate headquarters is expected to begin in September 2004 and run through March 2005. During March 2004, we incurred $1.1 million of costs related to our corporate relocation activities, primarily related to employee severance and termination benefits. We expect such costs to continue through March 2005 as we complete our relocation activities. We currently estimate the costs of these activities to total approximately $34 million.

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Reorganization, Restructuring and Impairment Charges

Reorganized NRG

     During the period January 1, 2004 through March 31, 2004, we recorded $6.3 million. These costs consist of bankruptcy related charges primarily related to professional fees.

     During the period January 1, 2004 through March 31, 2004, we reviewed the recoverability of our long-lived assets in accordance with the guidelines of SFAS No. 144. As a result of this review, we recorded no impairment charges.

Predecessor Company

     During the period January 1, 2003 through March 31, 2003, we also incurred total restructuring charges of approximately $21.4 million consisting of bankruptcy related charges.

     During the period January 1, 2003 through March 31, 2003, we reviewed the recoverability of our long-lived assets in accordance with the guidelines of SFAS No. 144 and as a result of this review; we recorded impairment charges of $0.7 million.

Other (Expense) Income

Reorganized NRG

     During the period January 1, 2004 through March 31, 2004, we recorded other expense of $83.4 million. Other expense consisted primarily of $102.2 million of interest expense and $1.7 million of write downs and losses on sales of equity method investments, offset by $17.7 million of equity in earnings of unconsolidated affiliates and $3.1 million of other income, net.

Predecessor Company

     During the period January 1, 2003 through March 31, 2003, we recorded other expense of $137.6 million. Other expense consisted primarily of $176.1 million of interest expense and $16.6 million of write downs and losses on sales of equity method investments, offset by $45.6 million of equity in earnings of unconsolidated affiliates and $9.3 million of other income, net.

Interest expense

Reorganized NRG

     Interest expense for the period January 1, 2004 through March 31, 2004 was $102.2 million, consisting of interest expense on both our project and corporate level interest bearing debt. Significant amounts of our corporate level debt were forgiven upon our emergence from bankruptcy and we refinanced significant amounts of our project level debt with corporate level high yield notes and term loans in December 2003. Interest expense includes $15 million of pre-payment penalties and $15 million write-off of deferred financing costs related to our January 2004 refinancing. Also included is the amortization of debt financing costs and fresh start accounting debt discount and premium amortization. Interest expense also includes the impact of any interest rate swaps that we’ve entered into to manage our exposure to changes in interest rates.

Predecessor Company

     Interest expense for the period January 1, 2003 through March 31, 2003 was $176.1 million, consisting of interest expense on both our project and corporate level interest bearing debt. In addition, interest expense includes the amortization of debt financing costs. Interest expense also was unfavorably impacted by adverse mark-to-market on certain interest rate swaps that we’ve entered into to manage our exposure to changes in interest rates. Due to our deteriorating financial condition, hedge accounting treatment was ceased for certain of our interest rate swaps causing changes in fair value to be recorded as interest expense.

Write Downs and (Gains)/Losses on Equity Method Investments

     As we periodically review our equity method investments for impairments we have taken write-downs and losses on sales of equity method investments during the period January 1, 2004 through March 31, 2004 and January 1, 2003 through March 31, 2003 of $1.7 million and $16.6 million, respectively.

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Write downs and losses on sales of equity method investments recorded in the consolidated statement of operations includes the following:

	Reorganized			Predecessor
	NRG			Company
	Three Months			Three Months
	Ended			Ended
	March 31, 2004			March 31, 2003
	(In thousands)
Calpine Cogeneration	$	(235	)	$	—
Loy Yang		1,973			—
NEO Corporation — Minnesota Methane		—			14,453
Kondapalli		—			1,293
ECKG		—			845
Total write downs losses of equity method investments	$	1,738		$	16,591

Calpine Cogeneration —In January 2004, we executed an agreement to sell our 20% interest in Calpine Cogeneration Corporation to Calpine Power Company. The transaction closed in March 2004 and resulted in net cash proceeds of $2.5 million and a net gain of $0.2 million.

Loy Yang —During first quarter of 2004, we wrote down our investment in Loy Yang by $2.0 million due to recent estimates of sales value. In April 2004, we completed the sale of our 25.4% interest in Loy Yang to Great Energy Alliance Corporation (GEAC), which resulted in net cash proceeds of $27.8 million.

NEO Corporation — Minnesota Methane —We recorded an impairment charge of $12.3 million during 2002 to write-down our 50% investment in Minnesota Methane. We recorded an additional impairment charge of $14.5 million during the first quarter of 2003. These charges were related to a revised project outlook and management’s belief that the decline in fair value was other than temporary. In May 2003, the project lenders to the wholly-owned subsidiaries of NEO Landfill Gas, Inc. and Minnesota Methane LLC foreclosed on our membership interest in the NEO Landfill Gas, Inc. subsidiaries and our equity interest in Minnesota Methane LLC. Upon completion of the foreclosure, we recorded a gain of $2.2 million. This gain resulted from the release of certain obligations.

Kondapalli— In the fourth quarter of 2002, we wrote down our investment in Kondapalli by $12.7 million due to recent estimates of sales value, which indicated an impairment of our book value that was considered to be other than temporary. On January 30, 2003, we signed a sale agreement with the Genting Group of Malaysia, or “Genting”, to sell our 30% interest in Lanco Kondapalli Power Pvt Ltd, or “Kondapalli”, and a 74% interest in Eastern Generation Services (India) Pvt Ltd (the O&M company). Kondapalli is based in Hyderabad, Andhra Pradesh, India, and is the owner of a 368 MW natural gas fired combined cycle gas turbine. In the first quarter of 2003, we wrote down our investment in Kondapalli by $1.3 million based on the final sale agreement. The sale closed on May 30, 2003 resulting in net cash proceeds of approximately $24 million and a gain of approximately $1.8 million. The gain resulted from incurring lower selling costs than estimated as part of the first quarter impairment.

ECKG— In September 2002, we announced that we had reached agreement to sell our 44.5% interest in the ECKG power station in connection with our Csepel power generating facilities, and our interest in Entrade, an electricity trading business, to Atel, an independent energy group headquartered in Switzerland. The transaction closed in January 2003 and resulted in cash proceeds of $65.3 million and a net loss of less than $1.0 million. In accordance with the purchase agreement, we were to receive additional consideration if Atel purchased shares held by our partner. During the second quarter of 2003, we received approximately $3.7 million of additional consideration.

Equity in Earnings of Unconsolidated Affiliates

Reorganized NRG

     During the period January 1, 2004 through March 31, 2004, we recorded $17.7 million of equity earnings from our investments in unconsolidated affiliates. Our investment in Mibrag comprised $6.3 million of this amount with our investment in West Coast Power and Gladstone comprising $6.0 million and $3.1 million, respectively. Our investment in West Coast Power generated favorable cash

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results, due to the pricing under the California Department of Water Resources contract, however our equity earnings in the project as reported in our results of operations has been reduced to reflect a non-cash basis adjustment resulting from adoption of the fresh start provisions of SOP 90-7.

Predecessor Company

     During the period January 1, 2003 through March 31, 2003, we recorded $45.6 million of equity earnings from our investments in unconsolidated affiliates. Our investment in Mibrag comprised $8.0 million of this amount with our investment in Gladstone comprising $4.4 million. Our investment in West Coast Power continued to generate favorable earnings of $27.3 million.

Other income, net

Reorganized NRG

     During the period January 1, 2004 through March 31, 2004, we recorded $3.1 million of other income, net. During this period other income, net consisted primarily of interest income earned on notes receivable.

Predecessor Company

     During the period January 1, 2003 through March 31, 2003, we recorded $9.3 million of other income, net. During this period other income, net consisted primarily of the favorable mark-to-market on our corporate level £160 million note which was cancelled in connection with our bankruptcy proceedings.

Income Tax

Reorganized NRG

     Income taxes for the period January 1, 2004 through March 31, 2004, was a tax expense of $14.2 million. For U.S. income tax purposes, the tax expense in 2004 is due to a reduction in deferred tax assets without a tax benefit for the corresponding reduction in valuation allowance. Due to the uncertainty of realization of deferred tax assets related to net operating losses and other temporary differences, our U.S. net deferred tax assets at December 5, 2003 were offset by a full valuation allowance of $1.3 billion in accordance with SFAS No. 109. SOP 90-7 requires that reductions in the valuation allowance as of December 5, 2003 (date of emergence) should first reduce intangible assets until exhausted and thereafter be reported as a direct addition to paid-in-capital. Consequently, our effective tax rate in post Bankruptcy emergence years will not benefit from reductions in the valuation allowance.

     As of March 31, 2004, the valuation allowance against U.S. and Foreign net operating loss carryforwards was $536.1 million and the valuation allowance against other deferred tax assets was $730.5 million. As of December 31, 2003, a valuation allowance of $559.7 million was provided to account for potential limitations on utilization of U.S. and Foreign net operating loss carryforwards, and a valuation allowance of $704.7 million was provided for other deferred tax assets. If unused, the U.S. net operating loss carryforward of $1.0 billion generated in 2002 and 2003 will expire by 2023. Foreign net operating loss carryforwards have no expiration date.

Predecessor Company

     During the period January 1, 2003 through March 31, 2003, we recorded income tax expense of $32.9 million. For U.S. income tax purposes, the tax expense in 2003 is due to an additional valuation allowance recorded against the deferred tax assets of NRG West Coast LLC as a result of its conversion from a corporation to a disregarded entity for federal income tax purposes.

Income on Discontinued Operations, net of income taxes

Reorganized NRG

     We classified as discontinued operations, the operations and gains/losses recognized on the sale of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. During the period January 1, 2004 through March 31, 2004, we recorded income on discontinued operations, net of income taxes of $2.4 million. During this period, discontinued operations consisted, of the results of our PERC, Cobee and McClain facilitates as all other discontinued operations were disposed of in prior periods.

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Predecessor Company

     We classified as discontinued operations, the operations and gains/losses recognized on the sale of projects that were sold or were deemed to have met the required criteria for such classification pending final disposition. During the period January 1, 2003 through March 31, 2003, we recorded income on discontinued operations, net of income taxes of $161.6 million consisting of the results from Killingholme, NLGI, NEO Corporation projects, TERI, Cahua and Energia Pacasmayo projects, which were disposed of in 2003. This amount also includes the results of our PERC, Cobee and McClain facilitates expected to be sold in 2004. The $161.6 million net gain is due primarily to the $191.2 million net gain recognized on the completion of the sale of our interest in Killingholme, offset by losses on our McClain and NEO Corporation projects.

Critical Accounting Policies and Estimates

     Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements and related disclosures in compliance with generally accepted accounting principles, or “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, and related disclosures of contingent assets and liabilities. The application of these policies necessarily involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges. 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, we evaluate our estimates, utilizing historic experience, consultation with experts and other methods we consider reasonable. In any case, actual results may differ significantly from our estimates. Any effects on our 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.

Liquidity and Capital Resources

     In connection with the consummation of the NRG plan of reorganization, on December 5, 2003 all shares of our old common stock were canceled and 100,000,000 shares of new common stock of NRG Energy were distributed pursuant to such plan to the holders of certain classes of claims. A certain number of shares of common stock were issued for distribution to holders of disputed claims as such claims are resolved or settled. In the event our disputed claims reserve is inadequate, it is possible we would have to issue additional shares of our common stock to satisfy such pre-petition claims or contribute additional cash proceeds. See Item 1 — Note 17 of the Consolidated Financial Statements of this Form 10-Q — Disputed Claims Reserve. Our authorized capital stock consists of 500,000,000 shares of NRG Energy common stock and 10,000,000 shares of Serial Preferred Stock. Further, a total of 4,000,000 shares of our common stock, representing approximately 4% of our outstanding common stock, are available for issuance under our long-term incentive plan.

     In addition to our issuance of new common stock, on December 23, 2003, we completed a note offering consisting of $1.25 billion of 8% Second Priority Senior Secured Notes due 2013 and we entered into a new Senior Secured Credit Facility consisting of a $950.0 million term loan facility, a $250.0 million funded letter of credit facility and a $250.0 million revolving credit facility. In January of 2004, we completed a supplementary note offering whereby we issued an additional $475.0 million of the 8% Second Priority Notes at a premium and used the proceeds to repay a portion of the $950.0 million term loan. As of May 1, 2004, we had $1.75 billion in aggregate principal amount of 8% Second Priority Notes outstanding, $444.8 million principal amount outstanding under the term loan and $129.6 million remains available under the funded letter of credit facility. As of May 1, 2004, we had not drawn down on our revolving credit facility.

     In March 2004, we entered into two interest rate hedges in support of our obligations under the 8% Second Priority Notes and the Senior Secured Credit Facility. Depending on market interest rates, we or the swap counterparty may be required to post collateral on a daily basis in support of both of these swaps, to the benefit of the other party.

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     In connection with the consummation of the NRG plan of reorganization, on December 5, 2003 we issued to Xcel Energy a $10.0 million non-amortizing promissory note, which will accrue interest at a rate of 3% per annum and mature 2.5 years after the effective date of the NRG plan of reorganization.

     A principal component of our plan of reorganization is a settlement with Xcel Energy in which Xcel Energy agreed to make a contribution consisting of cash in the aggregate amount of up to $640 million to be paid in three separate installments following the effective date of our plan of reorganization. The Xcel Energy settlement agreement resolves any and all claims existing between Xcel Energy and us and/or our creditors and, in exchange for the Xcel Energy contribution, Xcel Energy is receiving a complete release of claims from us and our creditors, except for a limited number of creditors who have preserved their claims as set forth in the order entered on November 24, 2003 confirming our plan of reorganization. On February 20, 2004, we received $288 million from Xcel Energy. On April 30, 2004 we received $328.5 million from Xcel as part of the third settlement. The remainder of the third settlement payment, $23.5 million, is expected from Xcel on May 30, 2004. We used the proceeds from the Xcel Energy settlement to reduce our creditor pool obligation. On February 20, 2004 and April 30, 2004 we made payments to former creditors of $163.0 million and $328.5 million, respectively.

     As part of the NRG plan of reorganization, we eliminated approximately $5.2 billion of corporate level bank and bond debt and approximately $1.3 billion of additional claims and disputes through our distribution of new common stock and $1.04 billion in cash among our unsecured creditors. In addition to the debt reduction associated with the restructuring, we used the proceeds of the recent note offering and borrowings under the Senior Secured Credit Facility to retire approximately $1.7 billion of project-level debt.

Capital Expenditures

     Capital expenditures were approximately $34.7 million for the three months ended March 31, 2004. We anticipate that our 2004 capital expenditures will be approximately $130 million and will relate to the operation and maintenance of our existing generating facilities.

Liquidity

     As of March 31, 2004 our liquidity remains a healthy $1.4 billion and consists of $1.0 billion of cash and restricted cash. Our liquidity also includes $0.3 billion of available capacity under our revolving line of credit and $0.1 billion of availability under our letter of credit facility. As of December 31, 2003 our liquidity was a healthy $1.2 billion and consisted of $0.7 billion of cash and restricted cash. Our liquidity also included $0.3 billion of available capacity under our revolving line of credit and $0.2 billion of availability under our letter of credit facility.

Cash Flows

	Reorganized NRG			Predecessor Company
	For the Three Months			For the Three Months
	Ended March 31,			Ended March 31,
	2004			2004
	(In thousands)
Net cash provided (used) by operating activities	$	350,155		$	(88,470	)
Net cash (used) provided by investing activities		(34,478	)		64,205
Net cash (used) by financing activities		(38,117	)		(23,758	)

Net Cash Provided (Used) By Operating Activities

Reorganized NRG

     For the three months ended March 31, 2004, cash provided by operating activities was $350.2 million. This was primarily a result of net income after non-cash charges of $166.1 million and $288.0 million received in connection with the Xcel Energy settlement agreement, offset by payments made in connection with our creditor pool obligation.

Predecessor Company

     For the three months ended March 31, 2003, cash used by operating activities was $88.5 million. During 2003, our financial condition deteriorated, primarily due to the overall downturn in the energy industry. As a result of deteriorating credit, we were required to PrePay and provide deposits for certain operating expenses. Other factors affecting working capital included an increase in accounts receivable, primarily related to increased energy prices, offset by an increase in accrued interest, due to our not making scheduled interest Payments.

Net Cash (Used) Provided By Investing Activities

Reorganized NRG

     For the three months ended March 31, 2004, cash used by investment activities was $34.5 million. This was primarily due to on-going capital improvement projects at our South Central facilities.

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Predecessor Company

     For the three months ended March 31, 2003, cash provided by investing activities was $64.2 million. This was primarily a result of cash proceeds received upon the sale of investments.

Net Cash (Used) Provided By Financing Activities

Reorganized NRG

     For the three months ended March 31, 2004, cash used by financing activities was $38.1 million. In January of 2004, we received proceeds through a supplementary note offering whereby we issued an additional $475.0 million of Second Priority Notes at a premium. We used the proceeds from this offering to repay $503.5 million of our recently issued term loan.

Predecessor Company

     For the three months ended March 31, 2003, cash used by financing activities was $23.8 million, resulting primarily from principal payments on short and long-term debt.

Off Balance-Sheet Arrangements

     As of March 31, 2004, we do not have any significant relationships with structured finance or special purpose entities that provide liquidity, financing or incremental market risk or credit risk.

     We have numerous investments with an ownership interest percentage of 50% or less in energy and energy related entities that are accounted for under the equity method of accounting. Our pro-rata share of non-recourse debt held by unconsolidated affiliates was approximately $885 million as of March 31, 2004. In the normal course of business we may be asked to loan funds to these entities on both a long and short-term basis. Such transactions are generally accounted for as accounts payables and receivables to/from affiliates and notes payables/receivables to/from affiliates and if appropriate, bear market-based interest rates.

Contractual Obligations and Commercial Commitments

     NRG Energy has a variety of contractual obligations and other commercial commitments that represent prospective cash requirements in addition to its capital expenditure programs. The following is a summarized table of contractual obligations.

	Payments Due by Period as of March 31, 2004
Contractual Cash									After
Obligations	Total		Short Term		1-3 Years		4-5 Years		5 Years
	(In thousands)
Long-term debt	$	3,886,249	$	534,836	$	98,768	$	95,850	$	3,156,795
Capital lease obligations		563,147		62,890		122,439		60,114		317,704
Operating leases		47,522		9,224		15,524		7,840		14,934
Total contractual cash obligations	$	4,496,918	$	606,950	$	236,731	$	163,804	$	3,489,433

	Amount of Commitment Expiration per Period as of March 31, 2004
	Total
Other Commercial	Amounts								After
Commitments	Committed		Short Term		1-3 Years		4-5 Years		5 Years
	(In thousands)
Draws on lines of credit	$	—	$	—	$	—	$	—	$	—
Issued letters of credit		203,342		203,342		—		—		—
Guarantees of subsidiaries		556,654		600		19,640		50,778		485,636
Guarantees of NRG PMI obligations		56,266		10,000		46,266		—		—
Total commercial commitments	$	816,262	$	213,942	$	65,906	$	50,778	$	485,636

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Derivative Instruments

     On March 24, 2004, we executed an interest rate swap agreement to mitigate our floating-rate interest exposure associated with our Senior Secured Credit Facility. The swap agreement became effective March 26, 2004 and terminates March 31, 2006. Under the agreement, we agree to pay quarterly a fixed interest rate on a notional amount of $400.0 million, commencing on March 31, 2004, and receive quarterly a floating-rate interest rate payment on the same notional amount. The floating rate is based upon three-month LIBOR, subject to a floor. During the three months ended March 31, 2004, we did not designate this transaction as an effective hedge of the expected cash flows; therefore, changes in fair value were recorded as interest expense.

     On March 24, 2004, we executed a second interest rate swap agreement to mitigate our fixed-rate interest exposure associated with our 8% Second Priority Notes. This swap agreement became effective March 26, 2004 and terminates December 15, 2013. The swap agreement has provisions for early termination that are linked to any prepayment of the 8% Second Priority Notes. Under the agreement, we agree to pay semi-annually in arrears, commencing June 15, 2004, a floating interest rate on a notional amount of $400.0 million, and receive semi-annually in arrears a fixed interest rate payment on the same notional amount. The floating interest rate is based upon six-month LIBOR plus a spread. Depending on market interest rates, we or the swap counterparty may be required to post collateral on a daily basis in support of both of these swaps, to the benefit of the other party. During the three months ended March 31, 2004, this transaction was designated as a fair value hedge; therefore, changes in fair value were recorded in other comprehensive income.

     The tables below disclose the trading 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 March 31, 2004 based on whether fair values are determined by quoted market prices or more subjective means; and indicate the maturities of contracts at March 31, 2004.

Trading Activity (Gains/(Losses), In thousands)

Fair value of contracts outstanding at December 31, 2002.	$	30,640
Contracts realized or otherwise settled during the period		(187,603	)
Other changes in fair values		107,049
Fair value of contracts outstanding at December 31, 2003.	$	(49,914	)
Contracts realized or otherwise settled during the period		(11,159	)
Other changes in fair values		(68,768	)
Fair value of contracts outstanding at March 31, 2004	$	(129,841	)

Sources of Fair Value (Gains/(Losses), In thousands)

	Fair Value of Contracts at March 31, 2004
	Maturity									Maturity			Total
	Less than			Maturity			Maturity			in excess			Fair
	1 Year			1-3 Years			4-5 Years			of 5 Years			Value
Prices actively quoted	$	(7,232	)	$	(14,416	)	$	(19,142	)	$	(89,051	)	$	(129,841	)
Prices based on models & other valuation methods		—			—			—			—			—
	$	(7,232	)	$	(14,416	)	$	(19,142	)	$	(89,051	)	$	(129,841	)

Item 3. Quantitative and Qualitative Disclosures About Market Risk

     Historically, we have used a variety of financial instruments to manage our exposure to fluctuations in foreign currency exchange rates on our international project cash flows, interest rates on our cost of borrowing and energy and energy related commodities prices.

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Currency Exchange Risk

     We expect to continue to be subject to currency risks associated with foreign denominated distributions from our international investments. In the normal course of business, we may receive distributions denominated in the Euro, Australian Dollar, British Pound, New Taiwanese Dollar and the Brazilian Real. We have historically engaged in a strategy of hedging foreign denominated cash flows through a program of matching currency inflows and outflows, and to the extent required, fixing the U.S. Dollar equivalent of net foreign denominated distributions with currency forward and swap agreements with highly credit worthy financial institutions. We would expect to enter into similar transactions in the future if management believes it to be appropriate.

     As of March 31, 2004, neither we, nor any of our consolidating subsidiaries, had any outstanding foreign currency exchange contracts.

Interest Rate Risk

     We are exposed to fluctuations in interest rates when entering into variable rate debt obligations to fund certain power projects. Exposure to interest rate fluctuations may be mitigated by entering into derivative instruments known as interest rate swaps, caps, collars and put or call options. These contracts reduce exposure to interest rate volatility and result in primarily fixed rate debt obligations when taking into account the combination of the variable rate debt and the interest rate derivative instrument. Our risk management policy allows us to reduce interest rate exposure from variable rate debt obligations.

     As of March 31, 2004, we had various interest rate swap agreements with notional amounts totaling approximately $1.5 billion, including two interest rate swaps we entered into in March 2004 in support of our obligations under the 8% Second Priority Notes and our term loan under our Senior Secured Credit Facility. If all consolidating swaps had been discontinued on March 31, 2004, we would have owed the counter parties approximately $71.1 million. Based on the investment grade rating of the counter-parties, we believe that our exposure to credit risk due to nonperformance by the counter-parties to our hedging contracts is insignificant.

     We have both long and short-term debt instruments that subject us to the risk of loss associated with movements in market interest rates. As of March 31, 2004, a 100 basis point change in the benchmark rate on our variable rate debt at our consolidated operations would impact net income by approximately $10.4 million.

     At March 31, 2004, the fair value of our fixed-rate debt was $2.2 billion, compared with the carrying amount of $2.2 billion. We estimate that a 1% decrease in market interest rates would have increased the fair value of our fixed-rate debt to $2.3 billion, or an increase of $106.8 million.

Commodity Price Risk

     As part of our overall portfolio, we manage the commodity price risk of our competitive supply activities and our electric generation facilities, including power sales, fuel and energy purchases and emission credits. In order to manage these risks, we may enter into fixed price contracts to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel and energy including forward contracts, future contracts, swaps, and options.

     We measure the sensitivity of our mark-to-market energy contracts to potential changes in market price using value at risk. Value at risk is a statistical model that attempts to predict risk of loss based on market price volatilities. We calculate value at risk using a variance/covariance technique that models positions using a linear approximation of their value. Our value at risk calculation includes mark-to-market and non mark-to-market energy assets and liabilities.

     Historically, we have utilized an un-diversified Value at Risk, or “VAR”, model to estimate a maximum potential loss in the fair value of our commodity portfolio including generation assets, load obligations and bilateral physical and financial transactions. The key assumptions for our VAR model include (1) a lognormal distribution of price returns (2) three day holding period, (3) a 95% confidence interval, and (4) market correlations of 0. The volatility estimate is based on the historical volatility for at-the-money call options. Based on these assumptions, we would expect the three-day change in fair value greater than or equal to the daily value at risk at least one day a month.

     In the first quarter of 2004, we have implemented a diversified VAR model to calculate the same estimate of potential loss in the fair value of our energy assets and liabilities including generation assets, load obligations and bilateral physical and financial transactions. We have implemented this change to increase the quality of our risk reporting and to meet industry standards. The key

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assumptions for our model include (1) a lognormal distribution of price returns (2) one day holding period (3) a 95% confidence interval and (4) market implied price volatilities and historical price correlations.

     Due to the inherent limitations of statistical measures such as value at risk, the relative immaturity of the competitive markets for electricity and related derivatives, and the seasonality of changes in market prices, the value at risk calculation may not capture the full extent of commodity price exposure. As a result, actual changes in the fair value of mark-to-market energy assets and liabilities could differ from the calculated value at risk, and such changes could have a material impact on our financial results.

     This model encompasses the following generating regions: ENTERGY, NEPOOL, NYPP, PJM, WSCC and MAIN. The estimated maximum potential loss in fair value of our commodity portfolio, calculated using the old VAR model and the new DVAR model is as follows:

	(In millions)
Quarter ending March 31, 2004 (Diversified)	$	36.7
Average		35.8
High		38.6
Low		34.7
Quarter ending March 31, 2004 (Former Un-diversified)		63.7
Average		70.1
High		118.4
Low		40.0
Year ending December 31, 2003 (Former Un-diversified)		115.7
Average		179.9
High		282.9
Low		106.9

     We have risk management policies in place to measure and limit market and credit risk associated with our power marketing activities. An independent department within our finance organization is responsible for the enforcement of such policies. We regularly review these policies to ensure they capture changes in industry best practices and market environment.

Credit Risk

     We are exposed to credit risk in our risk management activities. Credit risk relates to the risk of loss resulting from the nonperformance by a counter party of its contractual obligations. We actively manage our counter-party credit risk. We have an established credit policy in place to minimize overall credit risk. Important elements of this policy include ongoing financial reviews of all counter-parties, established credit limits, as well as monitoring, managing and mitigating credit exposure.

Item 4. Controls and Procedures

     Our management has, with the participation of our principal executive and principal financial officers, conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the “Act”), as of the end of the quarter covered by this Form 10-Q. Based on that evaluation management concluded that our disclosure controls and procedures were effective as of that time. Management noted, however, that as previously announced, we are moving our corporate headquarters from Minneapolis, Minnesota to West Windsor, New Jersey. Management notes that it expects substantial transition and turnover of staff, including in the accounting and finance departments, as a result of this move of our corporate headquarters.

     This turnover may impact our ability to ensure that information that is required to be disclosed under the Act is accumulated and communicated to management in a manner that would allow timely decisions regarding required disclosure. We are taking steps to address these concerns. We recently hired Robert Flexon as our new Chief Financial Officer, effective March 29, 2004, and James Ingoldsby as our new Controller, effective May 3, 2004. In addition, we recently hired a new Director of Internal Audit and are in the process of hiring a Chief Risk Officer. To address transition issues, we have implemented a transition plan and established a staff retention bonus

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program. We have dedicated and will continue to dedicate the appropriate resources to resolve any transition issues and ensure the continued functioning and effectiveness of our disclosure control and procedures environment, however, there can be no assurance that we will be successful in that regard.

     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.

     Except as set forth above, there have been no significant changes in our disclosure controls and procedures environment or in other factors that could significantly affect these controls subsequent to the date of the evaluation referenced above.

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

     For a discussion of material legal proceedings in which we were involved through March 31, 2004, see Note 17 “Commitments and Contingencies” to our consolidated financial statements contained in Part I, Item 1 of this Form 10-Q.

Item 3. Defaults Upon Senior Securities

     We have identified the following material defaults with respect to the indebtedness of our significant subsidiaries as of March 31, 2004:

$554 million, Credit and Reimbursement Agreement dated November 12, 1999, as amended, between, LSP Kendall Energy LLC, Societe General, as Administrative Agent and the other parties thereto

• Liens placed against project assets

• Failure to achieve project completion

     In April 2004, Kendall executed an agreement with its lenders resolving the defaults under its credit facility. As required by this settlement agreement, Kendall prepaid $10.5 million in principal on its credit facility on April 21, 2004.

$181 million Loan Agreement dated November 30, 2001, as amended, between McClain LLC and Westdeutsche Landesbank Girozentrale, as Administrative Agent

• Failure to fund the debt service reserve account

• Failure to comply with revenue allocation procedures under Article 3 of the Energy Management Services Agreement

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

10.1*     Letter Agreement dated March 5, 2004 between NRG Energy and Scott J. Davido

10.2*     Letter Agreement dated March 5, 2004 between NRG Energy and Ershel C. Redd Jr.

10.3*     Letter Agreement dated March 5, 2004 between NRG Energy and John P. Brewster

10.4*     Letter Agreement dated March 5, 2004 between NRG Energy and Timothy W. O’Brien

10.5*     Letter Agreement dated February 19, 2004 between NRG Energy and Robert C. Flexon

31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

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32 Certification of Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

* Exhibit relates to compensation arrangement

(b) Reports on Form 8-K:

     NRG Energy filed reports on Form 8-k on the following dates during the quarter ended March 31, 2004:

Form 8-K, filed on January 7, 2004, to provide information under Item 5 regarding distributions to Class 5 (NRG unsecured claims) creditors.

Form 8-K, filed on January 30, 2004, to provide information under Item 5 regarding the issuance $475 million of bonds in the tack-on offering.

Form 8-K, filed on March 2, 2004, to provide information under Item 5 regarding the postponement of our 2003 earnings conference call.

Form 8-K, filed on March 11, 2004, to provide information under Item 12 regarding our financial and operating results for the fiscal year 2003.

Form 8-K, filed on March 16, 2004, to provide information under Item 9 regarding certain organizational changes.

Form 8-K, filed on May 3, 2004, to provide information under Item 7 regarding an amendment to the credit agreement dated as of December 23, 2003.

Form 8-K, filed on May 3, 2004, to provide information under Item 4 that PricewaterhouseCoopers LLP would decline to stand for re-election as the company’s independent auditors.

Form 8-K, filed on May 3, 2004, to provide information under Item 5 that we initiated a search for a new independent auditor.

Form 8-K, filed on May 7, 2004 to provide under Item 5 notice of our entering into an agreement to sell our interest in a generating plant located in Batesville, Mississippi.

Cautionary Statement Regarding Forward Looking Information

     This quarterly report includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act of 1934, as amended (the Exchange Act). The words “believes,” “projects,” “anticipates,” “plans,” “expects,” “intends,” “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statement. These factors, risks and uncertainties include, but are not limited to, the following:

• Lack of comparable financial data due to adoption of Fresh Start reporting;

• Our ability to timely engage new independent auditors;

• Our ability to successfully and timely close transaction to sell certain of our assets;

• Adverse rulings with respect to our RMR agreements resulting in our Paying refunds in Connecticut;

• The potential impact of the planned corporate relocation on workforce requirements including the loss of institutional knowledge and inability to maintain existing processes.

• Hazards customary to the power production industry and the possibility that we may not have adequate insurance to cover losses as a result of such hazards;

• Our inability to enter into intermediate and long-term contracts to sell power and procure fuel on terms and prices acceptable to us;

• Increasing competition in wholesale power markets that may require additional liquidity for us to remain competitive;

• 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;

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

• 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 we are relying on single suppliers or single customers at a particular facility;

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

• 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 our revenue collection, increase our costs and engender enhanced federal and state regulatory requirements;

• Limitations on our ability to control projects in which we have less than a majority interest;

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

• Changes in government regulation, including but not limited to the pending changes of market rules, market structures and design, rates, tariffs, environmental regulations and regulatory compliance requirements imposed by the Federal Energy Regulatory Commission, state commissions, other state regulatory agencies, the Environmental Protection Agency, the National Energy Reliability Council, transmission providers, Regional Transmission Organizations, Independent System Operators, or “ISOs,” or other regulatory or industry bodies;

• Price mitigation strategies employed by ISOs that result in a failure to adequately compensate our generation units for all of their costs;

• Employee workforce factors including the hiring and retention of key executives, collective bargaining agreements with union employees and work stoppages;

• 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 our bankruptcy filing;

• The impact of the bankruptcy proceedings on our operations going forward, including the impact on our ability to negotiate favorable terms with suppliers, customers, landlords and others;

• Acts of terrorism both in the United States and internationally;

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

• Material developments with respect to and ultimate outcomes of legal proceedings and investigations relating to our past and present activities;

• The fact that certain of our subsidiaries remain in bankruptcy, and the potential that additional subsidiaries may file for bankruptcy in the future;

• The exposure of certain of our project subsidiaries to the exercise of rights and remedies by project lenders or shareholders as a result of our chapter 11 bankruptcy reorganization;

• 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 supply costs or availability due to higher demand, shortages, transportation problems or other developments; environmental incidents; or electric transmission or gas pipeline system constraints;

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• Our ability to borrow additional funds and access capital markets;

• Our substantial indebtedness and the possibility that we may incur additional indebtedness going forward;

• Significant operating and financial restrictions placed on us by the indenture governing our recent note offerings and our new credit facility;

• Restrictions on the ability to pay dividends, make distributions or otherwise transfer funds to us contained in the debt and other agreements of certain of our subsidiaries and project affiliates generally; and

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

     We undertake no obligation to publicly 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 our actual results to differ materially from those contemplated in any forward-looking statements included in this quarterly report should not be construed as exhaustive.

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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 ENERGY, INC.
(Registrant)

/s/ DAVID CRANE
David Crane,
Chief Executive Officer

/s/ ROBERT FLEXON
Robert Flexon,
Executive Vice President and CFO
(Principal Financial and Accounting Officer)

Date: May 10, 2004

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