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: June 30, 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	55402
(Address of principal executive offices)	(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.

Yes x No o

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

Yes x No o

     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.

Yes x No o

     As of August 2, 2004, there were 100,006,798 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 - 5
Consolidated Statements of Stockholders’ Equity (Deficit)		6 - 7
Consolidated Statements of Cash Flows		8
Notes to Consolidated Financial Statements		9 - 41
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations		42 - 58
Item 3 Quantitative and Qualitative Disclosures About Market Risk		59 - 60
Item 4 Controls and Procedures		60 - 61
Part II — OTHER INFORMATION
Item 1 Legal Proceedings		61
Item 3 Defaults Upon Senior Securities		61
Item 5 Other Information		61
Item 6 Exhibits and Reports on Form 8-K		61 - 62
Cautionary Statement Regarding Forward Looking Information		62 - 64
SIGNATURES		65
Exhibit Index		66
Amended and Restated By-Laws
Code of Conduct
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of Controller Pursuant to Section 302
Certification of CEO, CFO and Controller

2

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

	Reorganized			Predecessor			Reorganized			Predecessor
	NRG			Company			NRG			Company
	Three Months						Six Months
	Ended						Ended
	June 30,			June 30,			June 30,			June 30,
	2004			2003			2004			2003
	(In thousands, except for per share amounts)
Operating Revenues
Revenues from majority-owned operations	$	573,674		$	441,599		$	1,173,992		$	936,609
Operating Costs and Expenses
Cost of majority-owned operations		353,750			381,845			735,801			759,432
Depreciation and amortization		53,168			63,768			108,174			122,906
General, administrative and development		45,837			39,147			82,329			87,663
Corporate relocation charges		5,645			—			6,761			—
Reorganization items		(2,661	)		6,334			3,589			6,334
Restructuring and impairment charges		1,676			269,631			1,676			291,767
Total operating costs and expenses		457,415			760,725			938,330			1,268,102
Operating Income/(Loss)		116,259			(319,126	)		235,662			(331,493	)
Other Income (Expense)
Minority interest in earnings of consolidated subsidiaries		(201	)		—			(709	)		—
Equity in earnings of unconsolidated affiliates		46,101			46,857			63,814			92,486
Write downs and gains/(losses) on sales of equity method investments		1,205			(132,436	)		(533	)		(149,027	)
Other income, net		8,052			(7,953	)		11,708			3,542
Interest expense		(66,225	)		(92,087	)		(159,371	)		(260,761	)
Total other expense		(11,068	)		(185,619	)		(85,091	)		(313,760	)
Income/(Loss) From Continuing Operations Before Income Taxes		105,191			(504,745	)		150,571			(645,253	)
Income Tax Expense		36,322			4,305			50,602			37,342
Income/(Loss) From Continuing Operations		68,869			(509,050	)		99,969			(682,595	)
Income/(Loss) on Discontinued Operations, net of Income Taxes		14,155			(99,351	)		13,290			61,562
Net Income/(Loss)	$	83,024		$	(608,401	)	$	113,259		$	(621,033	)
Weighted Average Number of Common Shares Outstanding — Basic		100,080						100,051
Income From Continuing Operations per Weighted Average Common Share — Basic	$	0.69					$	1.00
Income From Discontinued Operations per Weighted Average Common Share — Basic		0.14						0.13
Net Income per Weighted Average Common Share — Basic	$	0.83					$	1.13
Weighted Average Number of Common Shares Outstanding — Diluted		100,478						100,214
Income From Continuing Operations per Weighted Average Common Share — Diluted	$	0.69					$	1.00
Income From Discontinued Operations per Weighted Average Common Share — Diluted		0.14						0.13
Net Income per Weighted Average Common Share — Diluted	$	0.83					$	1.13

See notes to consolidated financial statements.

3

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (REORGANIZED COMPANY)

(Unaudited)

	June 30,			December 31,
	2004			2003
	(In thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	820,876		$	551,223
Restricted cash		151,673			116,067
Accounts receivable — trade, less allowance for doubtful accounts of $322 and $0		313,649			201,908
Xcel Energy settlement receivable		—			640,000
Current portion of notes receivable — affiliates		1,917			200
Current portion of notes receivable		123,060			65,141
Taxes receivable		14,824			—
Inventory		203,672			194,926
Derivative instruments valuation		11,670			772
Prepayments and other current assets		229,961			222,178
Current deferred income taxes		961			1,850
Current assets — discontinued operations		56,955			119,574
Total current assets		1,929,218			2,113,839
Property, Plant and Equipment
In service		3,935,915			3,885,465
Under construction		104,794			139,171
Total property, plant and equipment		4,040,709			4,024,636
Less accumulated depreciation		(119,487	)		(11,800	)
Net property, plant and equipment		3,921,222			4,012,836
Other Assets
Equity investments in affiliates		677,684			737,998
Notes receivable, less current portion — affiliates		122,539			130,152
Notes receivable, less current portion		612,118			691,444
Intangible assets, net of accumulated amortization of $34,404 and $5,212		356,068			432,361
Debt issuance costs, net of accumulated amortization of $4,992 and $454		63,038			74,337
Derivative instruments valuation		53,474			59,907
Funded letter of credit		250,000			250,000
Other assets		116,129			123,145
Non-current assets — discontinued operations		451,785			618,968
Total other assets		2,702,835			3,118,312
Total Assets	$	8,553,275		$	9,244,987

See notes to consolidated financial statements.

4

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (REORGANIZED COMPANY)
(Unaudited)

	June 30,		December 31,
	2004		2003
	(In thousands)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	96,385	$	801,229
Short-term debt		17,826		19,019
Accounts payable — trade		137,033		158,683
Accounts payable — affiliates		6,372		7,040
Accrued taxes		—		16,095
Accrued property, sales and other taxes		16,136		22,322
Accrued salaries, benefits and related costs		33,072		19,331
Accrued interest		20,038		8,982
Derivative instruments valuation		20,979		429
Creditor pool obligation		25,000		540,000
Other bankruptcy settlement		221,283		220,000
Other current liabilities		113,773		102,861
Current liabilities — discontinued operations		23,121		110,190
Total current liabilities		731,018		2,026,181
Other Liabilities
Long-term debt and capital leases		3,922,417		3,327,782
Deferred income taxes		144,522		149,493
Postretirement and other benefit obligations		110,842		105,946
Derivative instruments valuation		159,567		153,503
Other long-term obligations		473,247		480,938
Non-current liabilities — discontinued operations		469,911		558,884
Total non-current liabilities		5,280,506		4,776,546
Total Liabilities		6,011,524		6,802,727
Minority Interest		5,673		5,004
Commitments and Contingencies
Stockholders’ Equity
Serial Preferred Stock; 10,000,000 shares authorized, none issued and outstanding at June 30, 2004 and December 31, 2003		—		—
Common stock; $.01 par value; 500,000,000 shares authorized; 100,006,798 shares at June 30, 2004 and 100,000,000 shares at December 31, 2003 issued and outstanding		1,000		1,000
Additional paid-in capital		2,410,751		2,403,429
Retained earnings		124,284		11,025
Accumulated other comprehensive income		43		21,802
Total stockholders’ equity		2,536,078		2,437,256
Total Liabilities and Stockholders’ Equity	$	8,553,275	$	9,244,987

See notes to consolidated financial statements.

5

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)

Three Months Ended June 30, 2004 and June 30, 2003

(Unaudited)

										Accumulated
	Common				Additional					Other			Total
					Paid-in		Retained Earnings/			Comprehensive			Stockholders’
(In thousands)	Stock		Shares		Capital		(Accumulated Deficit)			Income/(Loss)			Equity/(Deficit)
Balances at March 31, 2003 (Predecessor Company)	$	—		—	$	2,227,692	$	(2,841,565	)	$	(139,004	)	$	(752,877	)
Net loss								(608,401	)					(608,401	)
Foreign currency translation adjustments and other											77,777			77,777
Deferred unrealized gain on derivatives, net											5,155			5,155
Comprehensive loss for the three months ended June 30, 2003														(525,469	)
Balances at June 30, 2003 (Predecessor Company)	$	—		—	$	2,227,692	$	(3,449,966	)	$	(56,072	)	$	(1,278,346	)
Balances at March 31, 2004 (Reorganized NRG)	$	1,000		100,000	$	2,406,771	$	41,260		$	(3,176	)	$	2,445,855
Net income								83,024						83,024
Foreign currency translation adjustments and other											(33,520	)		(33,520	)
Deferred unrealized gain on derivatives, net											36,739			36,739
Comprehensive income for the three months ended June 30, 2004														86,243
Equity based compensation				7		3,980								3,980
Balances at June 30, 2004 (Reorganized NRG)	$	1,000		100,007	$	2,410,751	$	124,284		$	43		$	2,536,078

See notes to consolidated financial statements.

6

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY/(DEFICIT)
Six Months Ended June 30, 2004 and June 30, 2003
(Unaudited)

										Accumulated
	Common				Additional					Other			Total
					Paid-in		Retained Earnings/			Comprehensive			Stockholders’
(In thousands)	Stock		Shares		Capital		(Accumulated Deficit)			Income/(Loss)			Equity/(Deficit)
Balances at December 31, 2002 (Predecessor Company)	$	—		—	$	2,227,692	$	(2,828,933	)	$	(94,958	)	$	(696,199	)
Net loss								(621,033	)					(621,033	)
Foreign currency translation adjustments and other											90,867			90,867
Deferred unrealized loss on derivatives, net											(51,981	)		(51,981	)
Comprehensive loss for the six months ended June 30, 2003														(582,147	)
Balances at June 30, 2003 (Predecessor Company)	$	—		—	$	2,227,692	$	(3,449,966	)	$	(56,072	)	$	(1,278,346	)
Balances at December 31, 2003 (Reorganized NRG)	$	1,000		100,000	$	2,403,429	$	11,025		$	21,802		$	2,437,256
Net income								113,259						113,259
Foreign currency translation adjustments and other											(35,933	)		(35,933	)
Deferred unrealized gain on derivatives, net											14,174			14,174
Comprehensive income for the six months ended June 30, 2004														91,500
Equity based compensation				7		7,322								7,322
Balances at June 30, 2004 (Reorganized NRG)	$	1,000		100,007	$	2,410,751	$	124,284		$	43		$	2,536,078

See notes to consolidated financial statements.

7

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Reorganized			Predecessor
	NRG			Company
	Six Months Ended
	June 30,
(In thousands)	2004			2003
Cash Flows from Operating Activities
Net income/(loss)	$	113,259		$	(621,033	)
Adjustments to reconcile net income/(loss) to net cash provided (used) by operating activities
Distributions in excess of (less than) equity in earnings of unconsolidated affiliates		4,751			(23,943	)
Depreciation and amortization		113,499			145,221
Amortization of debt issuance costs		20,060			11,090
Amortization of debt discount		11,795			—
Deferred income taxes		49,384			36,525
Minority interest		2,089			466
Unrealized (gains)/losses on derivatives		(21,458	)		17,796
Asset impairment		1,676			347,913
Write downs and losses on sales of equity method investments		533			148,841
Gain on sale of discontinued operations		(13,012	)		(218,536	)
Amortization of power contracts and emission credits		34,517			—
Cash provided (used) by changes in certain working capital items, net of acquisition affects
Accounts receivable		(111,054	)		(43,608	)
Xcel Energy settlement receivable		640,000			—
Accrued taxes		(29,285	)		(18,603	)
Inventory		(8,439	)		13,550
Prepayments and other current assets		(2,065	)		(74,262	)
Accounts payable		(27,626	)		264,106
Accounts payable — affiliates		213			4,788
Accrued property, sales and other taxes		(7,065	)		5,398
Accrued salaries, benefits and related costs		20,192			(3,769	)
Accrued interest		14,883			126,578
Other current liabilities		(506,368	)		(117,355	)
Cash used by changes in other assets and liabilities		16,878			22,869
Net Cash Provided by Operating Activities		317,357			24,032
Cash Flows from Investing Activities
Proceeds on sale of equity method investments		29,693			89,223
Proceeds on sale of discontinued operations		59,190			—
Investments in equity method investments and projects		(566	)		(369	)
Decrease in notes receivable, net		15,208			9,405
Capital expenditures		(64,676	)		(56,605	)
Increase in restricted cash and trust funds		(37,291	)		(14,137	)
Net Cash Provided by Investing Activities		1,558			27,517
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt, net		490,631			5,342
Deferred debt issuance costs		(8,497	)		(7,474	)
Principal payments on short and long-term debt		(567,806	)		(31,390	)
Net Cash Used by Financing Activities		(85,672	)		(33,522	)
Change in Cash from Discontinued Operations		10,822			24,062
Effect of Exchange Rate Changes on Cash and Cash Equivalents		25,588			(93,163	)
Net Increase (Decrease) in Cash and Cash Equivalents		269,653			(51,074	)
Cash and Cash Equivalents at Beginning of Period		551,223			360,860
Cash and Cash Equivalents at End of Period	$	820,876		$	309,786

See notes to consolidated financial statements.

8

NRG ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note 1 — Organization

General

     NRG Energy, Inc., or NRG Energy, the “Company”, “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.

     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 June 30, 2004, three entities remain in bankruptcy.

     As part of the NRG plan of reorganization, Xcel Energy, Inc., or 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 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 June 30, 2004, we owned interests in 55 power projects in five countries having an aggregate net generation capacity of approximately 18,000 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 1,700 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. 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. One-year term “reliability must-run contracts” with the California Independent System Operator for approximately 600 MW in the San Diego area are expected to be renewed for 2005.

     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 2,100 MW in various international markets, including Australia, Europe and Brazil.

     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 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. West Coast Power has arranged for power marketing and fuel management with affiliates of our other partner, Dynegy, Inc. We operate substantially all of our generating assets, including the West Coast Power plants.

     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.

9

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 AICPA 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 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 our Annual Report on Form 10-K for the year ended December 31, 2003. 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 (consisting of normal, recurring accruals) necessary to present fairly our consolidated financial position as of June 30, 2004, the results of our operations and stockholders’ equity/(deficit) for the three and six months ended June 30, 2004 and 2003, and our cash flows for the six months ended June 30, 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 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, or SFAS No. 141, “Business Combinations.”

Comparability of Financial Information

     Due to the adoption of Fresh Start as of December 5, 2003, the Reorganized NRG Energy 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 Energy and the Predecessor Company.

Note 3 — Discontinued Operations

     SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” 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/(loss) 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 and six months ended June 30, 2004, discontinued operations included our NRG McClain LLC; Penobscot Energy Recovery Company, or PERC; Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or Cobee; Hsin Yu and LSP Energy projects. For the three and six months ended June 30, 2003, discontinued operations included our NRG 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, Hsin Yu and LSP Energy projects. Summarized results of operations of discontinued operations were as follows:

10

	Reorganized NRG		Predecessor Company			Reorganized NRG		Predecessor Company
	Three Months Ended		Three Months Ended			Six Months Ended		Six Months Ended
	June 30, 2004		June 30, 2003			June 30, 2004		June 30, 2003
			(In thousands)
Operating revenues	$	43,257	$	60,590		$	102,080	$	136,377
Operating and other expenses		40,996		156,608			99,702		261,756
Pretax income/(loss) from operations of discontinued components		2,261		(96,018	)		2,378		(125,379	)
Income tax expense		4		1,267			986		1,787
Income/(loss) from operations of discontinued components		2,257		(97,285	)		1,392		(127,166	)
Disposal of discontinued components — pre-tax gain/(loss), net		13,307		(2,066	)		13,307		188,728
Income tax expense		1,409		—			1,409		—
Disposal of discontinued components — gain/(loss), net		11,898		(2,066	)		11,898		188,728
Income/(loss) on discontinued operations, net of income taxes	$	14,155	$	(99,351	)	$	13,290	$	61,562

     The assets and liabilities of the discontinued operations are reported in the balance sheets as of June 30, 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 June 30, 2004, within our Power Generation Segment, the NRG McClain and LSP Energy projects are included in the Other North America classification; all other projects have been sold as of June 30, 2004. As of December 31, 2003, within our Power Generation segment, the PERC, NRG McClain and LSP Energy projects are included in the Other North America classification and the Cobee and Hsin Yu projects are included in the Other International classification.

	Power Generation
	Other North
June 30, 2004	America
	(In thousands)
Cash	$	1,736
Restricted cash		40,255
Receivables, net		8,181
Inventory		5,366
Prepaids and other current assets		1,417
Current assets — discontinued operations	$	56,955
PP&E, net	$	439,017
Other non-current assets		12,768
Non-current assets — discontinued operations	$	451,785
Current portion of long-term debt	$	5,448
Accounts payable — trade		2,284
Accrued liabilities		15,239
Other current liabilities		150
Current liabilities — discontinued operations	$	23,121
Long-term debt	$	287,279
Other non-current liabilities		182,632
Non-current liabilities — discontinued operations	$	469,911

11

	Power Generation
	Other North		Other
December 31, 2003	America		International		Total
	(In thousands)
Cash	$	4,294	$	8,264	$	12,558
Restricted cash		60,292		—		60,292
Receivables, net		12,675		11,272		23,947
Inventory		8,722		3,537		12,259
Prepaids and other current assets		3,732		6,786		10,518
Current assets — discontinued operations	$	89,715	$	29,859	$	119,574
PP&E, net	$	487,752	$	75,251	$	563,003
Non-current deferred tax asset		—		31,469		31,469
Other non-current assets		14,765		9,731		24,496
Non-current assets — discontinued operations	$	502,517	$	116,451	$	618,968
Current portion of long-term debt	$	6,206	$	49,743	$	55,949
Accounts payable — trade		3,056		23,050		26,106
Accrued liabilities		15,292		3,981		19,273
Other current liabilities		6,139		2,723		8,862
Current liabilities — discontinued operations	$	30,693	$	79,497	$	110,190
Long-term debt	$	313,739	$	19,779	$	333,518
Minority interest		31,879		406		32,285
Other non-current liabilities		184,970		8,111		193,081
Non-current liabilities — discontinued operations	$	530,588	$	28,296	$	558,884

     NRG McClain — On July 9, 2004, NRG McClain completed the sale of its 77% interest in the McClain Generating Station to Oklahoma Gas & Electric Company. The Oklahoma Municipal Power Authority will continue to own the remaining 23% interest in the facility. The proceeds of $160.2 million from the sale will be used to repay outstanding project debt under the secured term loan and working capital facility. A loss of $3.2 million was recognized as of June 30, 2004 based upon the final terms of the sale.

     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 that reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of $18.4 million, resulting in a gain of $2.0 million, net of tax.

     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 a gain of $2.8 million.

     LSP Energy — 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. A gain of approximately $16.0 million is expected upon completion of the sale.

     Hsin Yu —During the second quarter of 2004, we entered into an agreement for the sale of our interest in our Hsin Yu project to a minority interest shareholder, Asia Pacific Energy Development Company Ltd., which reached financial closing in May 2004. Upon completion of the transaction, we received net proceeds of $1.0 million, resulting in a gain of approximately $10.3 million, resulting from our negative equity in the project. In addition, although we have no continuing involvement in the project, we retained the prospect of receiving an additional $1.0 million in additional proceeds upon final closing of Phase II of the project.

     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

12

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 foreclosed on our membership interest in the NLGI subsidiaries and our equity interest in Minnesota Methane. Together with a $2.2 million gain recorded upon completion of the foreclosures of the related equity investees (see Note 4), there was no material net gain or loss recognized as a result of these foreclosures.

Note 4 — Write Downs and Gains/(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 include the following:

	Reorganized NRG		Predecessor Company			Reorganized NRG			Predecessor Company
	Three Months		Three Months			Six Months			Six Months
	Ended		Ended			Ended			Ended
	June 30, 2004		June 30, 2003			June 30, 2004			June 30, 2003
	(In thousands)
Calpine Cogeneration	$	500	$	—		$	735		$	—
Loy Yang		705		(139,972	)		(1,268	)		(139,972	)
NEO Corporation — Minnesota Methane		—		2,196			—			(12,257	)
Kondapalli		—		1,812			—			519
ECKG		—		3,714			—			2,869
Other		—		(186	)		—			(186	)
Total write downs and gains/(losses) on sales of equity method investments	$	1,205	$	(132,436	)	$	(533	)	$	(149,027	)

     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. During the second quarter of 2004, we received additional consideration on the sale of $0.5 million, resulting in an adjusted net gain of $0.7 million.

     Loy Yang — We recorded an impairment charge of $111.4 million during 2002 and an additional impairment charge of $140.0 million during the second quarter of 2003 based on a third party market evaluation and bids received in response to marketing Loy Yang for possible sale. During the 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 and a gain of $0.7 million. This resulted in an adjusted loss of $1.3 million for the six months ended June 30, 2004.

     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 foreclosed on our membership interest in the NEO Landfill Gas, Inc. subsidiaries and our equity interest in Minnesota Methane. Upon completion of the foreclosure, we recorded a gain of $2.2 million on the related equity investments. This gain resulted from the legal release of certain obligations.

     Lanco Kondapalli Power Pvt Ltd, or 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 to sell our 30% interest in Kondapalli and a 74% interest in Eastern Generation Services (India) Pvt Ltd. 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, resulting in a net gain of $0.5 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 gain of $2.9 million.

13

Note 5 — Reorganization Items and Restructuring and Impairment Charges

     Reorganization items and restructuring and impairment charges included in operating expenses in the consolidated statements of operations include the following:

	Reorganized NRG			Predecessor Company		Reorganized NRG		Predecessor Company
	Three Months Ended			Three Months Ended		Six Months Ended		Six Months Ended
	June 30, 2004			June 30, 2003		June 30, 2004		June 30, 2003
	(In thousands)
Reorganization items	$	(2,661	)	$	6,334	$	3,589	$	6,334
Restructuring charges		—			46,691		—		68,161
Impairment charges		1,676			222,940		1,676		223,606
Total	$	(985	)	$	275,965	$	5,265	$	298,101

     Reorganization items – We recorded a net credit of $2.7 million related to reorganization items for the three months ended June 30, 2004. These items relate primarily to the settlement of obligations recorded under Fresh Start. We incurred total reorganization items of approximately $3.6 million for the six months ended June 30, 2004. We incurred total reorganization items of approximately $6.3 million for the three and six months ended June 30, 2003, respectively. 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.

     Restructuring charges - We incurred total restructuring charges of approximately $46.7 million and $68.2 million for the three and six months ended June 30, 2003, respectively. These costs consist of employee separation costs and advisor fees.

     Impairment charges - 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 $1.7 million in impairment charges for the three and six months ended June 30, 2004 and $222.9 million and $223.6 million for the three and six months ended June 30, 2003, respectively which included the following:

		Reorganized NRG		Predecessor Company		Reorganized NRG		Predecessor Company
		Three Months Ended		Three Months Ended		Six Months Ended		Six Months Ended
Project Name	Project Status	June 30, 2004		June 30, 2003		June 30, 2004		June 30,2003		Fair Value Basis
				(In thousands)
New Roads Holding LLC	Non-operating asset	$	1,676	$	—	$	1,676	$	—	Projected cash flows
Devon Power LLC	Operating at a loss		—		64,198		—		64,198	Projected cash flows
Middletown Power LLC	Operating at a loss		—		157,323		—		157,323	Projected cash flows
Other	Terminated		—		1,419		—		2,085
Total impairment charges		$	1,676	$	222,940	$	1,676	$	223,606

Note 6 — Asset Retirement Obligation

     Effective January 1, 2003, we adopted SFAS No. 143, “Accounting for Asset Retirement Obligations”. 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 or 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 environmental 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 following represents the balances of the asset retirement obligation as of December 31, 2003 and the additions and accretion

14

of the asset retirement obligation for the six months ended June 30, 2004, which is included in other long-term obligations in the consolidated balance sheet.

			Accretion for the
	Beginning Balance		Six Months Ended		Ending Balance
Description	December 31, 2003		June 30, 2004		June 30, 2004
			(In thousands)
South Central Region	$	2,638	$	91	$	2,729
Northeast Region		11,750		400		12,150
Australia		9,438		526		9,964
Non-Generation		1,334		45		1,379
Alternative Energy		834		29		863
Total	$	25,994	$	1,091	$	27,085

Note 7 — Inventory

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

	June 30,		December 31,
	2004		2003
	(In thousands)
Fuel oil	$	84,861	$	75,272
Coal		58,179		59,555
Natural gas		1,200		856
Other fuels		88		75
Spare parts		54,532		54,522
Emission credits		4,478		4,478
Other		334		168
Total inventory	$	203,672	$	194,926

Note 8 — Property, Plant and Equipment

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

	June 30,			December 31,
	2004			2003
	(In thousands)
Facilities and equipment	$	3,784,274		$	3,732,391
Land and improvements		133,684			134,888
Office furnishings and equipment		17,957			18,186
Construction in progress		104,794			139,171
Total property, plant and equipment		4,040,709			4,024,636
Accumulated depreciation		(119,487	)		(11,800	)
Net property, plant and equipment	$	3,921,222		$	4,012,836

Note 9 — Summarized Financial Information of Affiliates

     We have a 50% interest in one company, West Coast Power, which 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 and six months ended June 30, 2004, we recorded equity earnings of $21.9 million and $27.9 million, respectively, for West Coast Power after adjustments for the reversal of $5.6 million and $7.6 million, respectively, of project level depreciation expense, offset by a decrease in earnings related to $30.6 million and $61.6 million, respectively, of 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

15

the project’s 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 $6.9 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, including interests owned by us and other parties for the periods shown below:

Results of Operations

	Three Months Ended				Six Months Ended
(In millions)	June 30, 2004		June 30, 2003		June 30, 2004		June 30, 2003
Operating revenues	$	314	$	267	$	598	$	526
Operating income	$	94	$	77	$	164	$	137
Net income (pre-tax)	$	94	$	72	$	164	$	131

Financial Position

	June 30,		December 31,
(In millions)	2004		2003
Current assets	$	332	$	257
Other assets		437		454
Total assets	$	769	$	711
Current liabilities	$	69	$	55
Other liabilities		8		8
Equity		692		648
Total liabilities and equity	$	769	$	711

     For several years, the Federal Energy Regulatory Commission, or FERC, has been engaged in investigations regarding potential manipulation of electrical and natural gas prices, and earlier this year, Dynegy, we and the West Coast Power entities commenced extensive settlement negotiations with FERC Staff; the People of the State of California ex rel. Bill Lockyer, Attorney General; the California Public Utility Commission, or 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. The parties have now reached a definitive, comprehensive settlement, which has been filed with FERC and awaits FERC approval.

     As part of the settlement agreement, 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 January 20, 2004. In addition, West Coast Power will forego: (1) past due receivables from the California Independent System Operator, or 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. For a two year period following FERC’s acceptance of the Settlement Agreement, West Coast Power will retain an independent engineering company to perform semi-annual audits of the technical and economic basis, justification and rationale for outages that occurred at its California generating plants during the previous six month period, and to have the results of such audits provided to the FERC Office of Market Oversight and Investigation without prior review by West Coast Power.

     West Coast Power and NRG Energy are fully reserved for both the past due receivables and the cash settlement as of June 30, 2004. West Coast Power is also subject to other legal matters and litigation. Other litigation and investigations respecting West Coast Power are set forth in detail in Note 17.

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

16

average remaining amortization period is two 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 and six months ended June 30, 2004 was approximately $12.4 million and $29.2 million, respectively. The annual aggregate amortization for each of the five succeeding years is expected to approximate $20.9 million in year one, $33.0 million in year two, $26.8 million in each of years three and four, and $20.3 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 six months ended June 30, 2004, we reduced our tax valuation allowance by $44.0 million (see Note 16) and recorded a corresponding reduction of $37.1 million related to our intangible assets at our wholly owned subsidiaries. The remaining $6.9 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. Intangible assets were also reduced by $10.0 million in connection with the recognition of certain tax credits to be claimed on our New York state franchise tax return.

Intangible assets consisted of the following:

	Power Sale			Emission
(In thousands)	Agreements			Allowances			Total
Original balance as of December 6, 2003	$	64,055		$	373,518		$	437,573
Amortization		(5,212	)		—			(5,212	)
Balance as of December 31, 2003		58,843			373,518			432,361
Tax valuation adjustment		(3,720	)		(33,377	)		(37,097	)
Other adjustments		—			(10,004	)		(10,004	)
Amortization		(19,274	)		(9,918	)		(29,192	)
Balance as of June 30, 2004	$	35,849		$	320,219		$	356,068

Predecessor Company

     We had intangible assets of $27 million at June 30, 2003, which were not amortized and consisted of goodwill. We also had intangible assets of $45.0 million at June 30, 2003, which were amortized and consisted of service contracts. Aggregate amortization expense recognized for the three and six months ended June 30, 2003 was approximately $1.0 million and $2.1 million, respectively.

Note 11 — Derivative Instruments and Hedging Activities

     SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, as amended, 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, or 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. Additionally, many of our commodity sales and purchase agreements that otherwise would be required to follow derivative accounting qualify as normal purchases and sales under SFAS No. 133, and are therefore exempt from fair value accounting treatment.

     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.

17

Accumulated Other Comprehensive Income (OCI)

     The following table summarizes the effects of SFAS No. 133 on our OCI balance attributable to hedged derivatives for the three months ended June 30, 2004:

	Energy			Interest			Foreign
(Gains/(Losses) In thousands)	Commodities			Rate			Currency		Total
Accumulated OCI balance at March 31, 2004	$	(15,271	)	$	(7,817	)	$	—	$	(23,088	)
Unwound from OCI during period:
— Due to unwinding of previously deferred amounts		9,408			3,272			—		12,680
Mark-to-market of hedge contracts		(3,079	)		27,138			—		24,059
Accumulated OCI balance at June 30, 2004	$	(8,942	)	$	22,593		$	—	$	13,651
Gains expected to unwind from OCI during next 12 months	$	13,138		$	24,750		$	—	$	37,888

     The following table summarizes the effects of SFAS No. 133 on our OCI balance attributable to hedged derivatives for the six months ended June 30, 2004:

	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		8,784			7,058		170			16,012
Mark-to-market of hedge contracts		(15,773	)		13,935		—			(1,838	)
Accumulated OCI balance at June 30, 2004	$	(8,942	)	$	22,593	$	—		$	13,651
Gains expected to unwind from OCI during next 12 months	$	13,138		$	24,750	$	—		$	37,888

     Losses of $12.7 million and $16.0 million were reclassified from OCI to current period earnings during the three and six months ended June 30, 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 and six months ended June 30, 2004 we recorded gains in OCI of approximately $24.1 million and losses of $1.8 million, respectively, related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of June 30, 2004 was an unrecognized gain of approximately $13.7 million. We expect $37.9 million of deferred net gains on derivative instruments accumulated in OCI to be recognized in earnings during the next twelve months.

Statement of Operations

     The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the three months ended June 30, 2004:

	Reorganized NRG
	Energy					Foreign
(Gains/(Losses) In thousands)	Commodities			Interest Rate		Currency		Total
Revenue from majority-owned subsidiaries	$	6,572		$	—	$	—	$	6,572
Equity in earnings of unconsolidated subsidiaries		10,293			—		—		10,293
Cost of operations		(1,129	)		—		—		(1,129	)
Total statement of operations impact before tax	$	15,736		$	—	$	—	$	15,736

18

     The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the six months ended June 30, 2004:

	Reorganized NRG
	Energy					Foreign
(Gains/(Losses) In thousands)	Commodities			Interest Rate		Currency		Total
Revenue from majority-owned subsidiaries	$	7,468		$	—	$	—	$	7,468
Equity in earnings of unconsolidated subsidiaries		9,135			—		—		9,135
Cost of operations		(1,632	)		—		—		(1,632	)
Interest expense		—			411		—		411
Total statement of operations impact before tax	$	14,971		$	411	$	—	$	15,382

     The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the three months ended June 30, 2003:

	Predecessor NRG
	Energy					Foreign
(Gains/(Losses) In thousands)	Commodities		Interest Rate			Currency		Total
Revenue from majority-owned subsidiaries	$	35,722	$	—		$	—	$	35,722
Equity in earnings of unconsolidated subsidiaries		2,158		—			—		2,158
Cost of operations		2,623		—			—		2,623
Interest expense		—		(33,369	)		—		(33,369	)
Total statement of operations impact before tax	$	40,503	$	(33,369	)	$	—	$	7,134

     The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the six months ended June 30, 2003:

	Predecessor NRG
	Energy						Foreign
(Gains/(Losses) In thousands)	Commodities			Interest Rate			Currency		Total
Revenue from majority-owned subsidiaries	$	33,293		$	—		$	—	$	33,293
Equity in earnings of unconsolidated subsidiaries		3,665			(222	)		—		3,443
Cost of operations		(9,155	)		—			—		(9,155	)
Other income		—			—			92		92
Interest expense		—			(45,608	)		—		(45,608	)
Total statement of operations impact before tax	$	27,803		$	(45,830	)	$	92	$	(17,935	)

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’ equity. 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 and six months ended June 30, 2004 and 2003.

     During the three and six months ended June 30, 2004, our pre-tax earnings were increased by an unrealized gain of $15.7 million and $15.0 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 and six months ended June 30, 2003, our pre-tax earnings were increased by an unrealized gain of $40.5 million and $27.8 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.

19

     During the three and six months ended June 30, 2004, we reclassified losses of $9.4 million and $8.8 million, respectively, from OCI to current period earnings and expect to reclassify approximately $13.1 million of deferred gains to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

     At June 30, 2004, we had hedge and non-hedge energy related commodities financial instruments extending through December 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 and six months ended June 30, 2004.

     During the three and six months ended June 30, 2004, pre-tax earnings were increased by an unrealized gain of $0 million and $0.4 million, respectively, 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 June 30, 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.

     During the three and six months ended June 30, 2003, pre-tax earnings were decreased by an unrealized loss of $33.4 million and $45.8 million, respectively, 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 and six months ended June 30, 2004, we reclassified losses of $3.3 million and $7.1 million, respectively, from OCI to current period earnings and expect to reclassify approximately $24.8 million of deferred gains to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

     At June 30, 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 and six months ended June 30, 2004 and 2003.

     During the three and six months ended June 30, 2004, our pre-tax earnings were not affected by any gain or loss associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.

     During the three and six months ended June 30, 2003, our pre-tax earnings were increased by unrealized gains of $0 and $92,000 associated with foreign currency hedging instruments not accounted for as hedges in accordance with SFAS No. 133.

     During the three months ended June 30, 2004, no amounts were reclassified from OCI to current period earnings. During the six months ended June 30, 2004, we reclassified losses of $0.2 million 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.

20

     As of June 30, 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. However, a significant amount of our subsidiaries’ debt and other obligations contain terms that require they be supported with letters of credit or cash collateral.

     As discussed below, our NRG McClain project debt was in default as of June 30, 2004, however, on July 9, 2004, NRG McClain executed a sale of its interest in the McClain Generating Station and subsequently used the proceeds to repay outstanding project debt under the secured term loan and working capital facility.

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 June 30, 2004, the interest rate on the term loan was 5.56%, based on the London Interbank Offering Rate, or LIBOR, plus a credit spread. The LIBOR portion is subject to a floor of 1.5%.

     As of June 30, 2004, the $250.0 million letter of credit facility was fully funded and reflected as a funded letter of credit on the June 30, 2004 balance sheet. As of June 30, 2004, $132.3 million in letters of credit had been issued under this facility, leaving $117.7 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, or 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 June 30, 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. 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

21

$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. On June 30, 2004, we had posted $17.8 million in collateral. As of August 2, 2004, we have posted $11.1 million in collateral in support of the swaps.

     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. 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.

Certain Events Related to Project Level Debt

NRG McClain LLC Project Debt

     On November 28, 2001, NRG McClain entered into a credit agreement with Westdeutsche Landesbank Girozentrale, or West LB AG’s, New York Branch and various other lending institutions for a $181.0 million secured term loan and an $8.0 million working capital facility. As of June 30, 2004 and December 31, 2003, the outstanding amount under this facility was $156.5 million. As of June 30, 2004, the interest rate on such outstanding borrowings was 4.625%.

     On September 17, 2002, NRG McClain 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 & Electric Company, or OG&E, for substantially all of the assets of McClain Generating Station and contemporaneously filed for bankruptcy pursuant to the asset purchase agreement. On July 9, 2004, NRG McClain completed the sale of its 77% interest in the McClain Generating Station to OG&E. The Oklahoma Municipal Power Authority will continue to own the remaining 23% interest in the facility. A portion of the proceeds of $160.2 million, from the sale, was used to repay outstanding project debt under the secured term loan and working capital facility. As of June 30, 2004, NRG McClain was recorded as a discontinued operation on the accompanying financial statements. NRG McClain continues to be in bankruptcy and in default, with the expectation that it will file a liquidating plan of reorganization, settle all its outstanding obligations and be subsequently dissolved.

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. The transition of our corporate headquarters has commenced and is expected to run through March 2005.

     We expect to incur $26.5 million of expenses in connection with corporate relocation charges. Relocating, recruiting and other employee-related transition costs are expected to be approximately $12.8 million. These costs and cash payments are expected to be incurred through first quarter of 2005. Severance and termination benefits of $8.6 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 are expected to be $5.1 million. These costs are expected to be incurred through first quarter of 2005 with cash payments being made through fourth quarter of 2006. A summary of the significant components of the restructuring liability is as follows:

	Balance at		Restructuring					Balance at
	December 31,		Related		Cash			June 30,
(In thousands)	2003		Charges		Payments			2004
Employee related transition costs	$	—	$	1,670	$	(1,670	)	$	—
Severance and termination benefits		—		4,024		(502	)		3,522
Lease termination costs		—		1,067		(18	)		1,049
Total	$	—	$	6,761	$	(2,190	)	$	4,571

     As of June 30, 2004, the restructuring liability was $4.6 million and is included in other current liabilities on the consolidated balance sheet. Charges related to the employee related transition costs, severance and termination benefits and lease termination costs are recorded at our corporate level within our Other segment, in the corporate relocation charges line on the consolidated statement of operations.

22

     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 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 common share is shown in the following table:

	Reorganized NRG
	Three Months Ended		Six Months Ended
	June 30, 2004		June 30, 2004
	(In thousands, except per share data)
Basic earnings per share
Numerator:
Income from continuing operations	$	68,869	$	99,969
Income on discontinued operations, net of income taxes		14,155		13,290
Net income	$	83,024	$	113,259
Denominator:
Weighted average number of common shares outstanding		100,080		100,051
Income from continuing operations per weighted average common share	$	0.69	$	1.00
Income from discontinued operations, net of income taxes per weighted average common share		0.14		0.13
Net income per weighted average common share — basic	$	0.83	$	1.13
Diluted earnings per share
Numerator
Income from continuing operations	$	68,869	$	99,969
Income on discontinued operations, net of income taxes		14,155		13,290
Net income	$	83,024	$	113,259
Denominator:
Weighted average number of common shares outstanding		100,080		100,051
Incremental shares attributable to the assumed exercise of outstanding stock options (treasury stock method)		—		—
Incremental shares attributable to the issuance of nonvested restricted stock units (treasury stock method)		398		163
Total dilutive shares		100,478		100,214
Income from continuing operations per weighted average common share – diluted	$	0.69	$	1.00
Income from discontinued operations, net of income taxes per weighted average common share - diluted		0.14		0.13
Net income per weighted average common share - diluted	$	0.83	$	1.13

     For the three and six months ended June 30, 2004, options totaling 770,751 and 786,751, respectively, 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 the period January 1, 2004 through June 30, 2004, we issued stock option grants for 307,000 shares of common stock under the Long-Term Incentive Plan at fair values between $19.90 and $22.24. These options have a three-year graded vesting schedule. Compensation expense recorded under the stock option grants for the three and six months ended June 30, 2004 was approximately $1.8 million and $3.1 million, respectively.

     Restricted stock units: During the period January 1, 2004 through June 30, 2004, we issued 655,100 Restricted Stock Units, or RSUs, under the Long-Term Incentive Plan at fair values between $19.90 and $23.00 per unit. These units cliff vest in three years. Compensation expense recorded under the RSUs for the three and six months ended June 30, 2004 was approximately $1.4 million and $2.1 million, respectively. For purposes of computing earnings per share, nonvested RSUs are not considered outstanding for

23

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 the period January 1, 2004 through June 30, 2004, we issued 100,961 Deferred Stock Units, or DSUs, under the Long-Term Incentive Plan at fair values between $19.95 and $21.05 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 and six months ended June 30, 2004 was approximately $0.8 million and $2.1 million, respectively. For the purposes of computing basic earnings per share, the DSUs are considered outstanding upon grant on a weighted average basis.

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 recast our prior period disclosures in a consistent manner.

     We conduct 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 and six months ended June 30, 2004 and 2003 is as follows:

	Reorganized NRG
	Three Months Ended June 30, 2004
	Wholesale Power Generation
	(In thousands)
			South					Other North
	Northeast		Central			West Coast		America			Australia
Operating Revenues	$	275,029	$	102,497		$	929	$	29,587		$	36,793
Corporate relocation charges		—		1			—		—			—
Reorganization items		28		(70	)		—		1			—
Restructuring and impairment charges		—		1,676			—		—			—
Write downs and gains/(losses) on sales of equity method investments		—		—			—		500			705
Income/(Loss) from Continuing Operations Before Income Taxes		56,230		16,494			23,237		(868	)		(8,278	)
Income tax expense (benefit)		—		—			185		409			(3,370	)
Income/(Loss) From Continuing Operations		56,230		16,494			23,052		(1,277	)		(4,908	)
Income/(Loss) on Discontinued Operations, net of Income Taxes		—		—			—		1,915			—
Net Income/(Loss)		56,230		16,494			23,052		638			(4,908	)
Balance Sheet Total Assets	$	2,000,169	$	1,138,749		$	319,937	$	1,965,970		$	869,228

24

	Reorganized NRG
	Three Months Ended June 30, 2004
	Wholesale Power Generation
	(In thousands)
	Other			Alternative		Other Non-
	International			Energy		Generation			Other			Total
Operating Revenues	$	39,374		$	18,833	$	71,778		$	(1,146	)	$	573,674
Corporate relocation charges		—			—		—			5,644			5,645
Reorganization items		(1	)		—		(528	)		(2,091	)		(2,661	)
Restructuring and impairment charges		—			—		—			—			1,676
Write downs and gains/(losses) on sales of equity method investments		—			—		—			—			1,205
Income/(Loss) from Continuing Operations Before Income Taxes		26,263			3,658		44,378			(55,923	)		105,191
Income tax expense (benefit)		5,306			4		435			33,353			36,322
Income/(Loss) From Continuing Operations		20,957			3,654		43,943			(89,276	)		68,869
Income/(Loss) on Discontinued Operations, net of Income Taxes		12,237			—		—			3			14,155
Net Income/(Loss)		33,194			3,654		43,943			(89,273	)		83,024
Balance Sheet Total Assets	$	807,787		$	64,648	$	552,773		$	834,014		$	8,553,275

	Predecessor Company
	Three Months Ended June 30, 2003
	Wholesale Power Generation
	(In thousands)
				South					Other North
	Northeast			Central			West Coast		America			Australia
Operating Revenues	$	201,299		$	92,820		$	4,953	$	19,667		$	34,408
Reorganization items		566			886			—		—			—
Restructuring and impairment charges		223,724			1,249			—		41,598			6
Write downs and gains/(losses) on sales of equity method investments		—			—			—		(186	)		(139,972	)
Income/(Loss) from Continuing Operations Before Income Taxes		(299,805	)		(1,090	)		38,729		(63,680	)		(146,612	)
Income tax expense (benefit)		—			—			264		732			(1,780	)
Income/(Loss) From Continuing Operations		(299,805	)		(1,090	)		38,465		(64,412	)		(144,832	)
Income/(Loss) on Discontinued Operations, net of Income Taxes		—			—			—		(100,480	)		—
Net Income/(Loss)		(299,805	)		(1,090	)		38,465		(164,892	)		(144,832	)
Balance Sheet Total Assets	$	2,461,126		$	1,374,882		$	466,675	$	2,610,196		$	545,208

25

	Predecessor Company
	Three Months Ended June 30, 2003
	Wholesale Power Generation
	(In thousands)
	Other		Alternative			Non-
	International		Energy			Generation		Other			Total
Operating Revenues	$	39,532	$	18,418		$	31,992	$	(1,490	)	$	441,599
Reorganization items		—		—			—		4,882			6,334
Restructuring and impairment charges		221		—			10		2,823			269,631
Write downs and gains/(losses) on sales of equity method investments		5,526		2,196			—		—			(132,436	)
Income/(Loss) from Continuing Operations Before Income Taxes		15,313		4,203			5,294		(57,097	)		(504,745	)
Income tax expense (benefit)		2,822		(52	)		148		2,171			4,305
Income/(Loss) From Continuing Operations		12,491		4,255			5,146		(59,268	)		(509,050	)
Income/(Loss) on Discontinued Operations, net of Income Taxes		4,593		3,043			—		(6,507	)		(99,351	)
Net Income/(Loss)		17,084		7,298			5,146		(65,775	)		(608,401	)
Balance Sheet Total Assets	$	1,459,490	$	89,555		$	345,752	$	657,985		$	10,010,869

	Reorganized NRG
	Six Months Ended June 30, 2004
	Wholesale Power Generation
	(In thousands)
			South					Other North
	Northeast		Central		West Coast			America			Australia
Operating Revenues	$	605,569	$	197,762	$	(2,393	)	$	50,422		$	99,022
Corporate relocation charges		—		1		—			—			—
Reorganization items		349		653		—			151			—
Restructuring and impairment charges		—		1,676		—			—			—
Write downs and gains/(losses) on sales of equity method investments		—		—		—			735			(1,268	)
Income/(Loss) from Continuing Operations Before Income Taxes		143,658		27,871		24,600			(10,770	)		8,122
Income tax expense (benefit)		—		—		337			744			(106	)
Income/(Loss) From Continuing Operations		143,658		27,871		24,263			(11,514	)		8,228
Income/(Loss) on Discontinued Operations, net of Income Taxes		—		—		—			933			—
Net Income/(Loss)		143,658		27,871		24,263			(10,581	)		8,228

	Reorganized NRG
	Six Months Ended June 30, 2004
	Wholesale Power Generation
	(In thousands)
	Other		Alternative		Other Non-
	International		Energy		Generation		Other			Total
Operating Revenues	$	79,440	$	32,485	$	113,447	$	(1,762	)	$	1,173,992
Corporate relocation charges		—		—		—		6,760			6,761
Reorganization items		—		—		160		2,276			3,589
Restructuring and impairment charges		—		—		—		—			1,676
Write downs and gains/(losses) on sales of equity method investments		—		—		—		—			(533	)
Income/(Loss) from Continuing Operations Before Income Taxes		40,617		4,203		53,151		(140,881	)		150,571
Income tax expense (benefit)		9,450		8		600		39,569			50,602
Income/(Loss) From Continuing Operations		31,167		4,195		52,551		(180,450	)		99,969
Income/(Loss) on Discontinued Operations, net of Income Taxes		12,357		—		—		—			13,290
Net Income/(Loss)		43,524		4,195		52,551		(180,450	)		113,259

26

	Predecessor Company
	Six Months Ended June 30, 2003
	Wholesale Power Generation
	(In thousands)
				South				Other North
	Northeast			Central		West Coast		America			Australia
Operating Revenues	$	440,864		$	196,927	$	6,373	$	36,740		$	82,424
Reorganization items		566			886		—		—			—
Restructuring and impairment charges		224,484			1,918		—		41,970			6
Write downs and gains/(losses) on sales of equity method investments		—			—		—		(186	)		(139,972	)
Income/(Loss) from Continuing Operations Before Income Taxes		(320,553	)		8,857		62,728		(99,333	)		(136,612	)
Income tax expense (benefit)		—			—		36,444		1,623			(1,263	)
Income/(Loss) From Continuing Operations		(320,553	)		8,857		26,284		(100,956	)		(135,349	)
Income/(Loss) on Discontinued Operations, net of Income Taxes		—			—		—		(108,773	)		—
Net Income/(Loss)		(320,553	)		8,857		26,284		(209,729	)		(135,349	)

	Predecessor Company Six Months Ended June 30, 2003
	Wholesale Power Generation
	(In thousands)
	Other			Alternative			Non-
	International			Energy			Generation		Other			Total
Operating Revenues	$	73,105		$	31,792		$	71,870	$	(3,486	)	$	936,609
Reorganization items		—			—			—		4,882			6,334
Restructuring and impairment charges		(3,352	)		—			26		26,715			291,767
Write downs and gains/(losses) on sales of equity method investments		3,388			(12,257	)		—		—			(149,027	)
Income/(Loss) from Continuing Operations Before Income Taxes		31,497			(10,219	)		12,762		(194,380	)		(645,253	)
Income tax expense (benefit)		5,987			(52	)		820		(6,217	)		37,342
Income/(Loss) From Continuing Operations		25,510			(10,167	)		11,942		(188,163	)		(682,595	)
Income/(Loss) on Discontinued Operations, net of Income Taxes		208,951			(22,955	)		—		(15,661	)		61,562
Net Income/(Loss)		234,461			(33,122	)		11,942		(203,824	)		(621,033	)

Note 16 — Income Taxes

     The income tax provisions for the six months ended June 30, 2004 and June 30, 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 tax expense for the three and six months ended June 30, 2004 was $36.3 million and $50.6 million, respectively, compared to a tax expense of $4.3 million and $37.3 million, respectively, for the same periods in 2003. The tax expense for the six months ended June 30, 2004 includes U.S. tax expense of $41.0 million and foreign tax expense of $9.6 million. The tax expense for the six months ended June 30, 2003 includes U.S. tax expense of $32.3 million and foreign tax expense of $5.0 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, “Accounting for Income Taxes”. SOP 90-7 requires that reductions in the valuation allowance as of December 5, 2003 (date of emergence) 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 LLC as a result of its conversion from a corporation to a disregarded entity for federal income

27

tax purposes. Subsequent to the conversion, NRG West Coast will no longer be taxed as an entity separate from NRG Energy.

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

     The effective income tax rate for the six months ended June 30, 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) 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 six months ended June 30, 2003 differs from the statutory federal income tax rate of 35% primarily due to limitations on tax benefits.

     As of June 30, 2004, the valuation allowance against U.S. and foreign net operating loss carryforwards was $368.8 million and the valuation allowance against other deferred tax assets was $699.3 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

     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 California Independent Service Operator, or 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 appealed that decision to the United States Court of Appeal for the Ninth Circuit. 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 respecting that decision, and the two appeals were consolidated. On July 6, 2004, the Ninth Circuit rejected the Attorney General’s appeals and affirmed both decisions of the district court, including the dismissal of all the Attorney General’s substantive claims. The Attorney General has now sought rehearing at the Ninth Circuit.

     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.

28

     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 was argued in June, 2004 and 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).

     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 coordinated cases, which were all filed in late 2000 and 2001 in various state courts throughout California. We are also a defendant in all of them. The cases 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, and that appeal was argued in June, 2004 and is pending. 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 the Millar, Pastorino, RDJ Farms, Century Theatres, EI Super Burrito, Leo’s, J&M Karsant, and Bronco 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.

29

     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, and Business and Professions Code, as well as 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.

     City of Tacoma, Department of Public Utilities, Light Division, v. American Electric Power Service Corporation, et al., United States District Court, Western District of Washington, Case No. C04-5325 RBL

     This action was filed in early June, 2004 in Washington federal district court. The complaint names over 50 defendants, including West Coast Power’s four operating subsidiaries and various Dynegy entities. The complaint also names both us and West Coast Power as “Non-Defendant Co-Conspirators.” Plaintiff alleges that defendants, acting in concert with some or all of the Non-Defendant Co-Conspirators, violated the federal Sherman Act by unlawfully withholding power generation from, and/or unlawfully inflating the apparent demand for power in, markets in California and elsewhere in the western United States, thereby causing plaintiff to pay power prices substantially above what it would have otherwise paid. Plaintiff alleges defendants’ unlawful activities began at least as early as May, 2000, and continued through at least the end of 2001. Plaintiff claims damages in excess of $175 million. We cannot predict the likelihood of an unfavorable outcome at this time.

     County of Santa Clara v. Sempra Energy, et al., San Diego County Superior Court

     This action was filed in early July, 2004 in California state court. Although we understand that the complaint names West Coast Power and various Dynegy entities among the numerous defendants, West Coast Power has not been served. The complaint apparently alleges violation of California’s Cartwright Act and Business and Professions Code and unjust enrichment relating to alleged reporting of false natural gas prices and trading information to inflate retail prices for defendants’ benefit. We cannot predict the likelihood of an unfavorable outcome at this time.

     City and County of San Francisco; The People of the State of California; Dennis J. Herrera v Sempra Energy, et al., San Diego County Superior Court

     This action was filed in early July, 2004 in California state court. The complaint names West Coast Power and various Dynegy entities among the numerous defendants. Like the above County of Santa Clara case, the complaint alleges violation of California’s Cartwright Act and Business and Professions Code and unjust enrichment, as well as unfair competition, asserting that defendants conspired and acted in concert to manipulate retail gas

30

prices, thereby allowing defendants to sell natural gas at prices far above competitive levels. We cannot predict the likelihood of an unfavorable outcome at this time

County of San Diego v. Sempra Energy, et al., San Diego County Superior Court

     This action was filed in late July, 2004 in California state court. The complaint names West Coast Power and various Dynergy entities among the numerous defendants. Like the above City and County of San Francisco case, the complaint asserts that defendants conspired to manipulate retail gas prices, thereby allowing defendants to sell natural gas at grossly inflated prices. We cannot predict the likelihood of an unfavorable outcome at this time.

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 made certain changes to Judge Birchman’s methodology, because of FERC Staff’s findings of manipulation in gas index prices. 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 California ex rel. Bill Lockyer, Attorney General; the California Public Utility Commission, or 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. The parties have now reached a definitive, comprehensive settlement, which has been filed with FERC and awaits FERC approval.

     As part of the settlement agreement, 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, or 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. For a two year period following FERC’s acceptance of the Settlement Agreement, West Coast Power will retain an independent engineering company to perform semi-annual audits of the technical and economic basis, justification and rationale for outages that occurred at its California generating plants during the previous six month period, and to have the results of such audits provided to the FERC Office of Market Oversight and Investigation without prior review by West Coast Power.

     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 statement of operations.

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-

31

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.

     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.

NRG Bankruptcy Cap on California Claims

     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, discussed above, alleges that the defendants, collectively, overcharged California ratepayers during 2000 by $4.0 billion.

Electricity Consumers Resource Council v. Federal Energy Regulatory Commission, Docket 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 installed capacity, or ICAP, market. ECRC claims that the implementation of the ICAP demand curve violates section 205 of the

32

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.

Consolidated Edison Co. of New York v. Federal Energy Regulatory Commission, Docket No. 01-1503

     Consolidated Edison and others petitioned the United States Court of Appeals for the District of Columbia Circuit for review of certain FERC orders in which FERC refused to order a redetermination of prices in the New York Independent System Operator, or NYISO, operating reserve markets for the period from January 29, 2000 to March 27, 2000. Petitioners alleged that the prices in the operating reserves markets were unduly elevated by approximately $65 million as a result of market power abuse and operating flaws. On November 7, 2003, the court issued a decision which found that the NYISO’s method of pricing spinning reserves violated the NYISO tariff. The court also required FERC to determine whether the exclusion from the non-spinning market of a generating facility known as Blenheim-Gilboa and resources located in western New York also constituted a tariff violation and/or whether these exclusions enabled NYISO to use its Temporary Extraordinary Procedure, or TEP, authority to require refunds. On June 25, 2004, the NYISO filed a motion requesting that it be permitted to supplement the record. The motion indicated that FERC had the authority to order refunds in the case because the failure to model Blenhein-Gilboa constituted a TEP. On July 16, 2004, we filed an objection to the NYISO’s motion, asserting that the failure to model was a conscious decision of the owners of that facility and that NYISO’s authority under TEP did not apply. It is unclear at this time whether FERC will require refunds, much less the amount of any such refunds. If refunds are required, NRG entities which may be affected include NRG Power Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill Power LLC. Although non-NRG-related entities will share responsibility for payment of such refunds, under the petitioners’ theory and calculations the cumulative exposure to our above-listed entities could exceed $23 million.

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 is about 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.

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, NRG Energy, Inc., NRG Dunkirk Operations, Inc., Dunkirk Power, LLC, NRG Huntley Operations, Inc., Huntley Power, LLC, NRG Northeast Generating, LLC, Northeast Generation Holding, LLC, NRG Eastern, LLC and NRG Operating Services, Inc., United States District Court for the Western District of New York, Civil Action No. 02-CV-0024S

     In January 2002, the New York Department of Environmental Conservation, or DEC, sued Niagara Mohawk Power Corporation, or NiMo, us and certain of our affiliates 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 as to the federal claims and without prejudice as to the state claims. 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. The parties have commenced written discovery, and the court has scheduled the trial on liability issues for March, 2006. For several months, the parties have been engaged in discussions respecting possible settlement of this matter. 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

33

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.

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. 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 these disputes. We cannot make an evaluation of the likelihood of an unfavorable outcome. The cumulative potential loss could amount to some $40 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 amount to some $40 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, the Louisiana Department of Environmental Quality, or 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 additional control equipment. To establish the interim limit, DEQ issued a

34

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. The DEQ is presently processing the permit application. 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.

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 have been 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 issues. The final report from the expert investigation process has been delivered to the court of arbitration. Expert testimony will be presented at a hearing scheduled for mid-August, 2004, and we expect the court to issue its decision shortly after the hearing. 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 later 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 $1.5 million and $28 million and have agreed to the terms of cease and desist orders. The CFTC requested additional related information from us and subpoenaed to appear for testimony a number of our present and former employees. We cooperated with the CFTC and submitted materials responsive to the CFTC’s requests, while vigorously denying that we engaged in any improper conduct. On July 1, 2004, we learned that the CFTC had filed a civil complaint against us in Minnesota federal district court, alleging that we engaged in false reporting of natural gas trades from August, 2001 to May, 2002. The CFTC’s complaint seeks only an injunction against future violations of the Commodity Exchange Act. We cannot at this time predict the outcome of this matter.

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 approximately $113 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 below. In early July,

35

2004, we reached an agreement in principle with GE resolving the disputed bankruptcy claims of GE and its subsidiaries. The parties are now preparing final documentation of the settlement. We cannot estimate the likelihood of an unfavorable outcome in our disputes with Siemens.

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 claimants. 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 note that the Gordon complaint, discussed above, alleges that the defendants, collectively, overcharged California ratepayers during 2000 by $4.0 billion.

Regulatory Issues

New England

     Consistent with expectations, the Peaking Unit Safe Harbor, or PUSH, bidding has not yielded sufficient revenues to cover all costs for most of the Company’s affected facilities. On January 16, 2004, the Company filed proposed reliability-must-run agreements, or RMR agreements, with FERC for the following facilities: Devon station units 11 – 14, Middletown station and Montville station. The RMR agreement filings requested FERC to establish cost of service rates. On March 18, 2004 FERC granted us a one day suspension of the rates, subject to refund, set the case for hearing and consolidated the case with other similar NRG cases before a settlement judge. In the March 18, 2004 order the FERC ruled that the RMR agreements would expire with the implementation of a locational installed capacity, or LICAP, market, which was expected to begin on June 1, 2004. On April 14, 2004 we filed a motion for rehearing with FERC requesting FERC to revise the termination date ruling. As of this date, FERC has not responded to the rehearing request.

     Prior to the March 18, 2004 order, Devon 11 – 14, Middletown 4 and Montville had been submitting PUSH bids. As a result of the March 18, 2004 order we received more money from the sale of energy and capacity for the period January 17, 2004 through March 18, 2004 than was allowed under the March 18, 2004 order. Therefore, on June 23, 2004, we filed a report (“ Report”) with the FERC showing that we received approximately $4.9 million more from the sales of energy and other services than was permitted under the March 18th order. The Report further stated, however, that ISO-NE owed us a total of approximately $18.5 million under the RMR Agreement for the same period. The Report further stated that ISO-NE had, as of the date of the Report, paid us only $2.6 million, with the result that we, rather than owing any refunds to ISO-NE, were owed an additional $11.0 million for the period. The FERC

36

has not yet acted on the Report.

     On February 6, 2004, we filed updated maintenance schedules for the tracking mechanism that provides for the payment by certain NEPOOL participants of third party maintenance expense incurred by Devon 11 – 14, Middletown, Montville and Norwalk Harbor for the period beginning April 1, 2004 and ending March 31, 2005. On April 1, 2004 FERC accepted the revised schedules, subject to refund, set the case for hearing and consolidated the case with other similar NRG cases before a settlement judge. In the April 1, 2004 order the FERC ruled that the tracking mechanism would expire with the implementation of a LICAP market, which is expected to begin on June 1, 2004. On April 14, 2004 we filed a motion for rehearing with FERC requesting FERC to revise the termination date ruling. As of this date, FERC has not responded to the rehearing request.

     On April 1, 2004, we filed with FERC true-up schedules for the third-party payment of our maintenance expenses for the period February 27, 2003 to December 31, 2003. On July 12, 2004 FERC accepted the true-up schedules, effective June 7, 2004, subject to refund, set them for hearing and consolidated the case with other similar cases before a settlement judge.

     In addition to the facilities noted above, the following of the Company’s quick-start facilities in Connecticut have submitted PUSH bids that have been approved by FERC: Cos Cob, Franklin Drive, Banford and Torrington. The existing RMR agreement between ISO-NE and the Company covering Devon station units 7 and 8 terminated on September 30, 2003. On October 2, 2003, the Company filed with FERC to extend the existing RMR agreement for the two Devon units. On December 1, 2003, FERC granted a one-day suspension of the rates, subject to refund, set the case for hearing and appointed a settlement judge. On February 25, 2004, a FERC sponsored technical conference occurred to review the costs associated with the two Devon units. In the technical conference, the costs relevant to the RMR agreements were discussed. ISO-NE has indicated in a letter dated February 27, 2004, that one of the Devon units will no longer be needed for reliability services.

     Therefore, on May 28, 2004, Devon 8 was deactivated. On May 28, 2004, a revised RMR agreement was filed with FERC for Devon 7 facility to account for the costs remaining after the deactivation of Devon 8. On July 12, 2004, FERC granted us a one day suspension of the proposed rate of $10.15 per KW-month subject to refund, set the case for hearing and consolidated the case with other similar NRG cases before a settlement judge.

     On March 1, 2004, ISO-NE filed a locational capacity proposal with FERC. Under the proposal, generators that are needed for reliability and have a capacity factor of 15% or less in 2003 would be eligible for a monthly capacity payment of $5.38 per KW-month. Most of the Company’s generators located in Connecticut satisfy this requirement. On June 2, 2004, FERC issued an order rejecting ISO-NE’s LICAP proposal. In the order, the FERC ruled that LICAP would not go into effect until January 1, 2006. Until the implementation of LICAP, the existing PUSH bidding rules and existing RMR agreements are to continue. New RMR agreements must also end when the LICAP market is implemented.

New York

     In April of 2003, the NYISO implemented a demand curve in its capacity market and scarcity pricing improvements in its energy market. The New York demand curve eliminated the previous market structure’s tendency to price capacity at either its cap (deficiency rate) or near zero. In a complaint filed with FERC on December 15, 2003, Consolidated Edison Company of New York, Inc. and other load-serving entities alleged that NYISO had used the wrong rate setting methodology to establish prices and rebates in the New York City markets for a portion of the summer capacity auction in 2003, and that this action resulted in overcharges to customers and overpayments to suppliers, including the Company, totaling approximately $21 million, with the Company’s share being approximately $5 million. On July 13, 2004, FERC denied the complaint.

PJM

     On April 2, 2003, Reliant Resources, Inc., or Reliant, filed a complaint against the Pennsylvania, Jersey, Maryland Interconnector area, or PJM, with FERC and suggested specific modifications to PJM’s price mitigation rules. On June 9, 2003, FERC rejected the Reliant modifications but required PJM to file a report to address the concerns of Reliant by September 30, 2003. The PJM market monitoring unit filed its compliance filing with FERC as required, but opted to continue its present mitigation practices. The present mitigation plan permits PJM to “cost-cap” the energy bids of certain generating facilities that were constructed prior to 1996. The cost capping method is based on a facility’s variable costs plus 10%. In addition, the PJM market monitoring unit filed to eliminate the exemption that units built after 1996 had from PJM’s mitigation measures. On May 6, 2004, FERC rejected the proposed extension of the cost capping mechanism to generating facilities built after 1996. In the order, the FERC approved the application of cost-capping mitigation method for facilities built prior to 1996 and were cost capped less than 80% of the time the facilities operated. The FERC required that for facilities that are cost capped 80% or more of their operating hours that are mitigated, are needed for reliability and are not

37

recovering sufficient revenue to cover their costs, that PJM must provide alternative methods of compensation. The FERC noted that such alternative compensation could consist of market design changes such as a higher bid cap or reliability must run agreements. FERC required that PJM file such a proposal by November 6, 2004. At this time it is unclear how this ruling will impact the Company. The Company continues to monitor these activities for any potential adverse impact to the Company’s financial position or results of operations.

PJM – West

     On December 31, 2003 and February 5, 2004, PJM filed proposed mitigation plans for the Commonwealth Edison, or Com Ed, franchise territory. Among the proposed changes was the adoption of the existing PJM energy market mitigation plan of “cost capping” and a new mitigation plan for the capacity market. PJM proposed that the proposed energy market mitigation plan would only be effective through the 2004 summer season but that the capacity mitigation plan would remain effective until April 1, 2005. Under the capacity mitigation proposal, capacity prices would be capped at $30 per MW-day except when capacity levels are less than 101% of required reserves, then the price cap would be $160 per MW-day. On March 24, 2004, FERC rejected the proposed mitigation plans. On April 23, 2004, PJM filed a rehearing request on the rejection of the capacity market mitigation proposal. In the rehearing request, PJM requested that the $30 per MW-day cap be approved and that during times of scarcity there would not be a price cap. FERC has not yet issued an order on the rehearing request.

     On May 1, 2004 Commonwealth Edison Corporation became a member of PJM.

Entergy

     On March 31, 2004, Entergy filed with FERC a proposal to have an independent person monitor Entergy’s operation of its transmission system. FERC has not ruled on this request. Also, it is unclear at this time how this recent development will impact the Company.

Note 18 — Guarantees

     In November 2002, the FASB issued FASB Interpretation, or FIN, 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 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.

     In the normal course of business, we may be asked to provide certain assurances to the counter-parties of our asset sales agreements, such assurances may take the form of a guarantee issued by NRG on behalf of a directly or indirectly held majority-owned subsidiary. Due to the inter-company nature of such arrangements (NRG is essentially guaranteeing its own performance) and the nature of the guarantee being provided (usually the typical representations and warrantees that are provided in any asset sales agreement), it is not our policy to recognize the value of such an obligation in our consolidated financial statements.

     In connection with the adoption of Fresh Start, all outstanding guarantees were considered new; accordingly we applied the provisions of FIN 45 to all those guarantees. Each guarantee was reviewed for the requirement to recognize a liability at inception. As a result, we recorded a $15.0 million liability, which is included in other long-term liabilities.

     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.

38

     As of June 30, 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	June 30, 2004
	(In thousands)
Guarantees of subsidiaries	$	511,066
Guarantees of NRG Power Marketing, Inc. obligations		38,500
Total	$	549,566

     As of June 30, 2004, the nature and details of our guarantees were as follows:

	Maximum Amount
Project or	(June 30, 2004)
Subsidiary	(In thousands)		Nature of Guarantee	Expiration	Triggering Event
Astoria/Arthur Kill	Indeterminate		Performance Under Asset Purchase Agreement	None stated	Non-performance
Cobee	$	12,500	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	$	6,357	Fund Superannuation (Pension) Reserve	September 8, 2012	Credit agreement default
Flinders	$	48,951	Debt Service Reserve Guaranty	September 8, 2012	Credit agreement default
Flinders	$	57,736	Plant Removal and Site Remediation Obligation	Undetermined	Non-performance
Flinders	$	69,930	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	$	218,907	Guaranty of Obligation to Purchase Gas	None stated	Non-payment
Gladstone	$	22,819	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
Hsin Yu	$	1,000	Guarantee of Obligations Under the Sale and Purchase Agreement	None stated	Non-performance or non-payment
Latin Power	Indeterminate		Subscription Commitment Guaranty	None stated	Non-performance
Loy Yang	$	25,370	Guarantee of Obligations Under the Sale and Purchase Agreement	April 7, 2011	Non-performance or non-payment
McClain	$	1,015	Obligation to Fund Debt Service Reserve Shortfall	None stated	Non-payment
MIBRAG	$	8,314	Guarantee of Share Purchase Agreement	None stated	Non-performance
Newport	$	7,500	Executory Contract	Undetermined	Non-payment
Other	$	17,933	Various	Various	Various
PMI	$	38,500	Guarantee on behalf of NRG Power Marketing Inc. for various projects	Various	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
Total	$	549,566

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.

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

39

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. We have contributed $1.0 million to the NRG pension plans during the six months ended June 30, 2004. We expect to contribute approximately $1.0 million to our postretirement medical plan in 2004.

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
	Reorganized NRG		Predecessor Company		Reorganized NRG		Predecessor Company
	Three Months Ended		Three Months Ended		Six Months Ended		Six Months Ended
	June 30, 2004		June 30, 2003		June 30, 2004		June 30, 2003
			(In thousands)
Service cost benefits earned	$	2,950	$	—	$	5,900	$	—
Interest cost on benefit obligation		738		—		1,476		—
Amortization of prior service cost		—		—		—		—
Expected return on plan assets		—		—		—		—
Recognized actuarial (gain)/loss		—		—		—		—
Net periodic benefit cost	$	3,688	$	—	$	7,376	$	—

	Other Benefits
	Reorganized NRG		Predecessor Company			Reorganized NRG		Predecessor Company
	Three Months Ended		Three Months Ended			Six Months Ended		Six Months Ended
	June 30, 2004		June 30, 2003			June 30, 2004		June 30, 2003
			(In thousands)
Service cost benefits earned	$	465	$	334		$	930	$	668
Interest cost on benefit obligation		630		525			1,260		1,050
Amortization of prior service cost		—		(6	)		—		(12	)
Expected return on plan assets		—		—			—		—
Recognized actuarial (gain)/loss		—		48			—		96
Net periodic benefit cost	$	1,095	$	901		$	2,190	$	1,802

2003 Medicare Legislation

     In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003, the Act, became law in the United States. The Act introduces a prescription drug benefit under Medicare as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare benefit. In accordance with FASB Staff Position FAS 106-1, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”, we have elected to defer recognition of the effects of the Act in any measures of the benefit obligation or cost. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require the Company to change previously reported information. Currently, we do not believe we will need to amend the postretirement benefit plans to benefit from the Act. The measurement date used to determine pension and other postretirement benefit measures for the plans is December 31.

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

40

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, was paid by Xcel Energy on May 28, 2004. We used the proceeds from the Xcel Energy settlement to reduce our creditor pool obligation. As of June 30, 2004 and December 31, 2003 the balance of our creditor pool obligation was $25.0 million and $540.0 million, respectively. On February 20, 2004, April 30, 2004 and May 28, 2004, we made payments of $163.0 million, $328.5 million and $23.5 million, respectively. In addition, our other bankruptcy settlement obligation as of June 30, 2004 and December 31, 2003 was $221.3 million and $220.0 million, respectively. This obligation relates to the allowed claims pending against our Audrain and Pike facilities. The net change in the balance of $1.3 million as of June 30, 2004 relates to a $2.6 million increase to the outstanding obligation offset by an increase of $1.3 million related 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.

41

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.

     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 acquisitions intended to complement the asset portfolios in our core regions.

     The wholesale energy industry entered a prolonged slump in 2001, from which it is only beginning to emerge. We expect that generally weak market conditions will continue for the foreseeable future in many U.S. markets. We further expect that the merchant power industry will continue to see corporate restructuring, debt restructuring, and consolidation over the coming years.

     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 June 30, 2004 include McClain and LSP Energy projects. For the three and six months ended June 30, 2004, discontinued results of operations include our McClain, PERC, Cobee, Hsin Yu and LSP Energy projects. All prior periods presented have been restated accordingly.

     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. 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 Registered Public Accounting Firm; Audit Committee. PricewaterhouseCoopers LLP served as our independent auditors from 1995 through 2003. On May 3, 2004, we announced that PricewaterhouseCoopers LLP had decided not to stand for re-election as our independent auditor for the year ended December 31, 2004. On May 24, 2004, the Audit Committee of our board of directors appointed KPMG LLP as our independent registered public accounting firm going forward.

     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 our emergence from bankruptcy, we adopted Fresh Start Reporting on December 5,

42

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 SFAS No. 141. Accordingly, our assets’ recorded values were adjusted to reflect their estimated fair values upon adoption of Fresh Start. 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 and emerging from bankruptcy, our historical financial information is not comparable to financial information for periods after our emergence from bankruptcy.

RESULTS OF OPERATIONS

     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.

Management’s discussion of our results of operations for the three months ended June 30, 2004 and for the three months ended June 30, 2003

Net Income/(Loss)

Reorganized NRG

     For the three months ended June 30, 2004, we recorded net income of $83.0 million, or $0.83 per diluted weighted average share of common stock. Our results were favorably impacted by the recent FERC-approved Settlement Agreement between us, Connecticut Light and Power, Select Energy, Inc., Duke Energy Trading and Marketing, L.L.C., Richard Blumenthal, Attorney General of the State of Connecticut, The Connecticut Department of Public Utility Control and the Connecticut Office of Consumer Counsel, whereby we received $38.4 million in settlement proceeds. The second quarter is generally a shoulder period in the energy industry with mild weather and fewer heating and/or cooling degree-days above normal. As such, our NEPOOL and Oswego facilities in the Northeast were not frequently called upon to generate power during the second quarter, as they are during severe weather.

Predecessor Company

     For the three months ended June 30, 2003, we recorded a net loss of $608.4 million. Our results were unfavorably impacted by $269.6 million of impairment and restructuring charges, $132.4 million of charges related to write downs and losses on sales of our equity method investments and $6.3 million of reorganization charges related to our entering into bankruptcy in May 2003. Our results were also unfavorably impacted by continued losses resulting from our Connecticut Light and Power Standard Offer Contracts caused by an increase in market price and a decrease in generation.

Revenues from Majority-Owned Operations

Reorganized NRG

     Revenues from majority-owned operations of $573.7 million for the three months ended June 30, 2004, included $339.5 million of energy revenues, $160.5 million of capacity revenues, $42.7 million of alternative energy revenues, $4.9 million of O&M fees and $26.1 million of other revenues, which include financial and physical gas sales, and non-cash contract amortization resulting from Fresh Start.

     Revenues from majority-owned operations during the three months ended June 30, 2004, were driven primarily by our North American operations, particularly our Northeast power generation facilities, and to a lesser extent our South Central and Australian operations. Though mild weather limited production from our intermediate and peaking plants in the Northeast, our energy revenues were largely in line with expectations for this shoulder period. Revenues from our Australian operations were also in line with expectations. Though an unplanned outage occurred during the quarter, revenues benefited from a strengthening Australian dollar and better than expected energy prices. Our capacity revenues are largely driven by our Northeast and South Central facilities. Our Connecticut facilities continue to benefit from the cost based reliability must run, or RMR agreement, which was authorized on January 17, 2004. This agreement entitles us to approximately $7.1 million of revenues per month, and was expected to be replaced by locational installed capacity, or LICAP, in June 2004. FERC recently postponed the LICAP implementation until January 1, 2006, and as such, the existing RMR

43

agreements will continue until that date. The rates under this agreement are not final and are subject to refund. In the South Central region, our long-term contracts generally provide for capacity payments. Our revenues during this period were adversely impacted by $8.6 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. Our revenues were also favorably impacted by the FERC approved Settlement Agreement between us and Connecticut Light and Power and others, whereby we received $38.4 million in settlement proceeds in June 2004.

Predecessor Company

     Revenues from majority-owned operations of $441.6 million for the three months ended June 30, 2003, included $174.9 million of energy revenues, $181.7 million of capacity revenues, $67.4 million of alternative energy revenues, $3.2 million of O&M fees and $14.4 million of other revenues, which include financial and physical gas sales.

     Revenues from majority-owned operations during the three months ended June 30, 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 three months ended June 30, 2004 was $353.8 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 mild demand for electricity in the second quarter, particularly in the Northeast Region, our cost of energy declined over the first quarter. Our intermediate and peaking facilities, which are fueled by more expensive fuel oil and natural gas, were not frequently called upon to generate power over the course of the quarter. We also benefited from a $12 million property tax credit. Our cost structure was unfavorably impacted by the non-cash amortization of the value of SO₂ allowances recorded on our balance sheet resulting from Fresh Start in the amount of $3.6 million.

Predecessor Company

     Our cost of majority-owned operations related to continuing operations for the three months ended June 30, 2003 was $381.8 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 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 three months ended June 30, 2004 was $53.2 million. Depreciation and amortization consists primarily of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property. Upon adoption of Fresh Start we 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 than what we had previously used primarily due to the age and condition of our fixed assets. In completing the process of establishing newly determined depreciable fixed asset values and remaining depreciable lives, we utilized our best estimates for determining depreciation expense in certain instances. As we have completed the process, we have recognized the impact of any adjustments as changes in estimates.

Predecessor Company

     Our depreciation and amortization expense related to continuing operations for the three months ended June 30, 2003 was $63.8

44

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 three months ended June 30, 2004 were $45.8 million or 8.0% 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. General, administrative and development costs have been adversely impacted by increased legal fees associated with asset divestitures, higher accounting costs, and higher labor costs associated with an increase in corporate headquarters staff in preparation for our headquarters relocation.

Predecessor Company

     Our general, administrative and development costs related to continuing operations for the three months ended June 30, 2003 were $39.1 million or 8.9% of operating revenue. General, administrative and development costs were 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 transition of the corporate headquarters has commenced and is expected to run through March 2005. During the three months ended June 30, 2004, we recorded $5.6 million for charges related to our corporate relocation activities, primarily for employee severance and termination benefits. We expect such charges to total approximately $26.5 million and to continue through March 2005 as we complete our relocation activities. These charges will be classified separately in our statement of operations, in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities". We currently estimate total costs associated with the corporate relocation to approximate $43 million, inclusive of the relocation charges mentioned above. All other costs and expenses relating to the corporate relocation, except for approximately $4 million of related capital expenditures, will be expensed as incurred and included in general, administrative and development expenses. Cash costs for 2004 are expected to be approximately $30 million.

Reorganization Items and Restructuring and Impairment Charges

Reorganized NRG

     During the three months ended June 30, 2004, we recorded a net credit of $2.7 million related to reorganization items. These items relate primarily to the favorable settlement of obligations recorded under Fresh Start.

     During the three months ended June 30, 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 $1.7 million of asset impairments related to the impairment to the realizable value of a turbine acquired in March 2000 from Cajun Electric.

Predecessor Company

     During the three months ended June 30, 2003, we incurred total reorganization items of $6.3 million for the three months ended June 30, 2003. 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.

     During the three months ended June 30, 2003, we incurred total restructuring charges of $46.7 million. These costs consist of employee separation costs and advisor fees. All amounts were paid during the first half of 2003.

     During the three months ended June 30, 2003, we reviewed the recoverability of our long-lived assets in accordance with the

45

guidelines of SFAS No. 144. As a result of this review, we recorded $222.9 million of asset impairments primarily related to our Connecticut facilities, Devon and Middletown, resulting from adverse regulatory developments affecting these facilities.

Other Income (Expense)

Reorganized NRG

     During the three months ended June 30, 2004, we recorded other expense of $11.1 million, which consisted primarily of $66.2 million of interest expense and $0.2 million of minority interest in earnings of consolidated subsidiaries, offset by $1.2 million of gains on sales of equity method investments, $46.1 million of equity in earnings of unconsolidated affiliates (including $21.9 million from our investment in West Coast Power LLC) and $8.0 million of other income, net.

Predecessor Company

     During the three months ended June 30, 2003, we recorded other expense of $185.6 million. Other expense consisted primarily of $92.1 million of interest expense, $132.4 million of write downs and losses on sales of equity method investments and $8.0 million in other income, net, offset by $46.9 million of equity in earnings of unconsolidated affiliates (including $27.7 million from our investment in West Coast Power LLC).

Interest expense

Reorganized NRG

     Interest expense for the three months ended June 30, 2004 was $66.2 million, consisting of interest expense on both our project and corporate level interest bearing debt. Also included in interest expense is the amortization of debt financing costs and the amortization expense related to debt discounts and premiums recorded as part of Fresh Start. Additionally, interest expense also includes the impact of any interest rate swaps that we have entered in order to manage our exposure to changes in interest rates.

Predecessor Company

     Interest expense for the three months ended June 30, 2003 was $92.1 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 during this period was favorably impacted by our ceasing to record interest expense on debt where it was probable that such interest would not be paid, such as the NRG corporate level debt (primarily bonds) and NRG Finance Company debt (construction revolver) due to our entering into bankruptcy in May 2003. Interest expense was unfavorably impacted by an adverse mark-to-market on certain interest rate swaps that we have entered in order 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 Sales of Equity Method Investments

     As part of our periodic review of our equity method investments for impairments, we have taken gains on sales of equity method investments for the three months ended June 30, 2004 totaling $1.2 million and write-downs and losses on sales of equity method investments of $132.4 million during the three months ended June 30, 2003.

46

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

	Reorganized		Predecessor
	NRG		Company
	Three Months		Three Months
	Ended		Ended
	June 30, 2004		June 30, 2003
	(In thousands)
Calpine Cogeneration	$	500	$	—
Loy Yang		705		(139,972	)
NEO Corporation — Minnesota Methane		—		2,196
Kondapalli		—		1,812
ECKG		—		3,714
Other		—		(186	)
Total write downs and gains/(losses) on sales of equity method investments	$	1,205	$	(132,436	)

     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. During the second quarter of 2004, we received additional consideration on the sale of $0.5 million, resulting in an adjusted net gain of $0.7 million.

     Loy Yang — We recorded an impairment charge of $111.4 million during 2002 and an additional impairment charge of $140.0 million during the second quarter of 2003 based on a third party market evaluation and bids received in response to marketing Loy Yang for possible sale. During the 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 and a gain of $0.7 million.

     NEO Corporation — Minnesota Methane — In May 2003, the project lenders to the wholly owned subsidiaries of NEO Landfill Gas, Inc. and Minnesota Methane foreclosed on our membership interest in the NEO Landfill Gas, Inc. subsidiaries and our equity interest in Minnesota Methane. Upon completion of the foreclosure, we recorded a gain of $2.2 million on the related equity investments. This gain resulted from the legal release of certain obligations.

     Kondapalli — On May 30, 2003 we sold our investment in Kondapalli 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 January 2003 we sold our 44.5% interest in ECKG and our interest in Entrade to Atel. 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 three months ended June 30, 2004, we recorded $46.1 million of equity earnings from our investments in unconsolidated affiliates. Our investment in West Coast Power comprised $21.9 million of this amount with our investment in Mibrag and Gladstone comprising $4.5 million and $3.5 million, respectively. Our investment in West Coast Power generated favorable cash results due to the pricing under the California Department of Water Resources contract. Additionally, increased ancillary service revenue, the ability to satisfy the CDWR contract with lower-than-expected purchased power, minimum load cost compensation power, and operating efficiencies favorably impacted West Coast Power’s operating results. However, our equity earnings in the project as reported in our results of operations have been reduced to reflect a non-cash basis adjustment resulting from adoption of Fresh Start.

     NRG’s equity earnings were also favorably impacted by $10.3 million of unrealized gain related to our Enfield investment. This gain is associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

47

Predecessor Company

     During the three months ended June 30, 2003, we recorded $46.9 million of equity earnings from our investments in unconsolidated affiliates. $37.9 million was generated by our domestic portfolio and $9.0 million from our international portfolio. Our investment in West Coast Power continued to generate favorable earnings due primarily from the CDWR contract and contributed $27.7 million in earnings this period.

Other income, net

Reorganized NRG

     During the three months ended June 30, 2004, we recorded $8.0 million of other income, net, consisting primarily of interest income earned on notes receivable and cash balances.

Predecessor Company

     During the three months ended June 30, 2003, we recorded an expense of $8.0 million for other income, net. During this period other income, net consisted primarily of the unfavorable mark-to-market on our corporate level £160 million note that was cancelled in connection with our bankruptcy proceedings.

Income Tax Expense

Reorganized NRG

     Income tax expense for the three months ended June 30, 2004, was $36.3 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) 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. The foreign tax expense for the three months ended June 30, 2004 is due to the earnings in foreign jurisdictions.

Predecessor Company

     During the three months ended June 30, 2003, we recorded income tax expense of $4.3 million. The U.S. tax expense is due to separate company income tax liabilities. The foreign tax expense for the three months ended June 30, 2003 is due to earnings in foreign jurisdictions.

Income (Loss) 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 three months ended June 30, 2004, we recorded income on discontinued operations, net of income taxes of $14.2 million. During this period, discontinued operations consisted of the results of our NRG McClain LLC, Penobscot Energy Recovery Company, or PERC, Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or Cobee, Hsin Yu and LSP Energy projects. All other discontinued operations were disposed of in prior periods. The $14.2 million income on discontinued operations is comprised primarily of a gain of $11.9 million, net of $1.4 million taxes, recognized on the sale of PERC, Cobee and Hsin Yu of $2.0 million, $2.8 million and $10.3 million, respectively, offset by a loss on the sale of McClain of $3.2 million.

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 three months ended June 30, 2003, we recorded loss on discontinued operations, net of income taxes of $99.4 million consisting of the results from our McClain,

48

PERC, Cobee, Killingholme, NEO Landfill Gas, Inc., three NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC), Timber Energy Resources, Inc., Cahua and Energia Pacasmayo, Hsin Yu and LSP Energy projects. The loss on discontinued operations of $97.3 million is comprised primarily of the impairment at our McClain facilities of $100.7 million. In addition, there was a net loss on sale of discontinued operations of $2.1 million.

Management’s discussion of our results of operations for the six months ended June 30, 2004 and for the six months ended June 30, 2003

Net Income/(Loss)

Reorganized NRG

     For the six months ended June 30, 2004, we recorded net income of $113.3 million, or $1.13 per weighted average share of diluted 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 power than expected. Additionally, our results benefited by locking in certain of our domestic coal costs. Our results were also favorably impacted by the FERC-approved Settlement Agreement between NRG and Connecticut Light and Power and others, whereby we received $38.4 million in settlement proceeds in June 2004.

Predecessor Company

     For the six months ended June 30, 2003, we recorded a net loss of $621.0 million. Our results were unfavorably impacted by $291.8 million of restructuring and impairment charges, $149.0 million of charges related to write downs and losses on our equity method investments and $6.3 million of reorganization charges related to our entering into bankruptcy in May 2003. Our results were also unfavorably impacted by continued losses resulting from our Connecticut Light and Power Standard Offer Contract caused by increased market prices and a decrease in generation and increased costs related to our restructuring activities.

Revenues from Majority-Owned Operations

Reorganized NRG

     Revenues from majority-owned operations of $1. 2 billion for the six months ended June 30, 2004, included $723.4 million of energy revenues, $299.1 million of capacity revenues, $88.8 million of alternative energy revenues, $10.5 million of O&M fees and $52.2 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 for the six months ended June 30, 2004, were driven primarily by our North American operations, primarily our Northeast facilities. 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 in January 2004. 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. Our Australian operations were favorably impacted by strong market prices driven by gas restrictions in January, record high temperatures in February and March, and favorable foreign exchange movements. Our capacity revenues are largely driven by our Northeast and South Central facilities. Our Connecticut facilities continue to benefit from the cost based reliability must run, or RMR agreement, which was authorized on January 17, 2004. The agreement entitles us to approximately $7.1 million of revenues per month, which was originally expected to be replaced by LICAP in June 2004. FERC recently postponed the LICAP implementation until January 1, 2006, and as such, the existing RMR agreements will continue until that date. The rates under this agreement are not final and are subject to refund. In the South Central region our long-term contracts generally provide for capacity payments. 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 during this period were adversely impacted by $25.6 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. Our revenues were also favorably impacted by the FERC-approved Settlement Agreement between us and Connecticut Light and Power and others, whereby we received $38.4 million in settlement proceeds in June 2004.

49

Predecessor Company

     Revenues from majority-owned operations of $936.6 million for the six months ended June 30, 2003, included $451.9 million of energy revenues, $316.2 million of capacity revenues, $106.0 million of alternative energy revenues, $7.1 million of O&M fees and $55.4 million of other revenues, which include financial and physical gas sales.

     Revenues from majority-owned operations during the six months ended June 30, 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 six months ended June 30, 2004 was $735.8 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 exceeded 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 in the amount of $9.9 million.

Predecessor Company

     Our cost of majority-owned operations related to continuing operations for the six months ended June 30, 2003 was $759.4 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 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 six months ended June 30, 2004 was $108.2 million. Depreciation and amortization consists primarily of the allocation of our historical depreciable fixed asset costs over the remaining lives of such property. Upon adoption of Fresh Start we 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 than what we had previously used primarily due to the age and condition of our fixed assets. In completing the process of establishing newly determined depreciable fixed asset values and remaining depreciable lives, we utilized our best estimates for determining depreciation expense in certain instances. As we have completed the process, we have recognized the impact of any adjustments to those estimates.

Predecessor Company

     Our depreciation and amortization expense related to continuing operations for the six months ended June 30, 2003 was $122.9 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.

50

General, Administrative and Development

Reorganized NRG

     Our general, administrative and development costs related to continuing operations for the six months ended June 30, 2004 were $82.3 million or 7.0% 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 costs related to continuing operations for the six months ended June 30, 2003 were $87.7 million or 9.4% of operating revenue. General, administrative and development costs were 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 transition of the corporate headquarters has commenced and is expected to run through March 2005. During the six months ended June 30, 2004, we recorded $6.8 million for charges related to our corporate relocation activities, primarily for employee severance and termination benefits. We expect such charges to total approximately $26.5 million and to continue through March 2005 as we complete our relocation activities. These charges will be classified separately in our statement of operations, in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities". We currently estimate total costs associated with the corporate relocation to approximate $43 million, inclusive of the relocation charges mentioned above. All other costs and expenses relating to the corporate relocation, except for approximately $4 million of related capital expenditures, will be expensed as incurred and included in general, administrative and development expenses.

     We expect to recognize a curtailment gain on our defined benefit pension plan in the third quarter of this year, as a substantial number of our current headquarters staff are expected to leave the company in this period. We do not believe that the curtailment gain will be significant, given the relatively short average service period of these employees.

Reorganization Items and Restructuring and Impairment Charges

Reorganized NRG

     During the six months ended June 30, 2004, we incurred total reorganization items of $3.6 million. 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.

     During the six months ended June 30, 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 $1.7 million of asset impairments related to the impairment to the realizable value of a turbine acquired in March 2000 from Cajun Electric.

Predecessor Company

     During the six months ended June 30, 2003, we incurred total reorganization items of $6.3 million. 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.

     During the six months ended June 30, 2003, we incurred total restructuring charges of $68.2 million. These costs consist of employee separation costs and advisor fees. All amounts were paid during the first half of 2003.

     During the six months ended June 30, 2003, 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 $223.6 million of asset impairments primarily related to our Connecticut facilities, Devon and Middletown, resulting from adverse regulatory developments affecting these facilities.

51

Other Income (Expense)

Reorganized NRG

     During the six months ended June 30, 2004, we recorded other expense of $85.1 million. Other expense consisted primarily of $159.4 million of interest expense, $0.7 million of minority interest in earnings of consolidated subsidiaries and $0.5 million of write downs and losses on sales of equity method investments, offset by $63.8 million of equity in earnings of unconsolidated affiliates (including $27.9 million from our investment in West Coast Power LLC) and $11.7 million of other income, net.

Predecessor Company

     During the six months ended June 30, 2003, we recorded other expense of $313.8 million. Other expense consisted primarily of $260.8 million of interest expense, $149.0 million of write downs and losses on sales of equity method investments, offset by $3.5 million in other income, net and $92.5 million of equity in earnings of unconsolidated affiliates (including $27.3 million from our investment in West Coast Power LLC).

Interest Expense

Reorganized NRG

     Interest expense for the six months ended June 30, 2004 was $159.4 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. In January 2004, we refinanced certain amounts of our recently issued term loans with additional corporate level high yield notes. As a result of this financing, interest expense includes $15 million of pre-payment penalties and a $15 million write-off of deferred financing costs. Also included in interest expense is the amortization of debt financing costs related to our corporate level debt and the amortization expense related to debt discounts and premiums recorded as part of Fresh Start. Interest expense also includes the impact of any interest rate swaps that we have entered in order to manage our exposure to changes in interest rates.

Predecessor Company

     Interest expense for the six months ended June 30, 2003 was $260.8 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 during this period was favorably impacted by our ceasing to record interest expense on debt where it was probable that such interest would not be paid, such as the NRG corporate level debt (primarily bonds) and the NRG Finance Company debt (construction revolver) due to our entering into bankruptcy in May 2003. Interest expense was unfavorably impacted by an adverse mark-to-market on certain interest rate swaps that we have entered in order to manage our exposure to changes in interest rates. Due to our deteriorating financial condition during such period, 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 Sales of Equity Method Investments

     As part of our periodic review of our equity method investments for impairments, we have taken write downs and losses on sales of equity method investments during the six months ended June 30, 2004 and six months ended June 30, 2003 of $0.5 million and $149.0 million, respectively.

52

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

	Reorganized			Predecessor
	NRG			Company
	Six Months			Six Months
	Ended			Ended
	June 30, 2004			June 30, 2003
	(In thousands)
Calpine Cogeneration	$	735		$	—
Loy Yang		(1,268	)		(139,972	)
NEO Corporation — Minnesota Methane		—			(12,257	)
Kondapalli		—			519
ECKG		—			2,869
Other		—			(186	)
Total write downs and losses on sales of equity method investments	$	(533	)	$	(149,027	)

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. During the second quarter of 2004, we received additional consideration on the sale of $0.5 million, resulting in an adjusted net gain of $0.7 million.

Loy Yang — We recorded an impairment charge of $111.4 million during 2002 and an additional impairment charge of $140.0 million during the second quarter of 2003 based on a third party market evaluation and bids received in response to marketing Loy Yang for possible sale. During the 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 and a loss of $1.3 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 on the related equity investments. This gain resulted from the release of certain obligations.

Kondapalli — 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, resulting in a net gain of $0.5 million. The gain resulted from incurring lower selling costs than estimated as part of the first quarter impairment.

ECKG — In January 2003, we sold our 44.5% interest in ECKG and our interest in Entrade to Atel. In accordance with the purchase agreement, we were to receive additional consideration if Atel purchased shares held by our partner. The transaction closed in January 2003 and resulted in cash proceeds of $65.3 million and a net gain of $2.9 million.

Equity in Earnings of Unconsolidated Affiliates

Reorganized NRG

     During the six months ended June 30, 2004, we recorded $63.8 million of equity earnings from our investments in unconsolidated affiliates. Our investment in West Coast Power comprised $27.9 million of this amount with our investment in Mibrag and Gladstone comprising $10.9 million and $6.7 million, respectively. Our investment in West Coast Power generated favorable cash 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 have been reduced to reflect a non-cash basis adjustment resulting from adoption of Fresh Start.

53

Predecessor Company

     During the six months ended June 30, 2003, we recorded $92.5 million of equity earnings from our investments in unconsolidated affiliates. Our investment in West Coast Power comprised $27.3 million of this amount with our investment in Mibrag and Gladstone comprising $8.0 million and $4.4 million, respectively.

Other Income, net

Reorganized NRG

     During the six months ended June 30, 2004, we recorded $11.7 million of other income, net, consisting primarily of interest income earned on notes receivable and cash balances.

Predecessor Company

     During the six months ended June 30, 2003, we recorded $3.5 million for other income, net. During this period other income, net consisted primarily of interest income earned on notes receivable and cash balances, offset in part by the unfavorable mark-to-market on our corporate level £160 million note that was cancelled in connection with our bankruptcy proceedings.

Income Tax Expense

Reorganized NRG

     Income tax expense for the six months ended June 30, 2004, was $50.6 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) 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. The foreign tax expense for the six months ended June 30, 2004 is due to earnings in foreign jurisdictions.

     As of June 30, 2004, the valuation allowance against U.S. and foreign net operating loss carryforwards was $368.8 million and the valuation allowance against other deferred tax assets was $699.3 million. 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 six months ended June 30, 2003, we recorded income tax expense of $37.3 million. The U.S. tax is due to separate company tax liabilities and an additional valuation allowance recorded against the deferred tax assets of NRG West Coast Power LLC as a result of its conversion to a disregarded entity for federal income tax purposes. The foreign tax expense for the six months ended June 30, 2003 is due to earnings in foreign jurisdictions. 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 provided for other deferred tax assets.

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 six months ended June 30, 2004, we recorded income on discontinued operations, net of income taxes of $13.3 million. During this period, discontinued operations consisted of the results of our NRG McClain LLC , PERC, Cobee, Hsin Yu and LSP Energy projects. All other discontinued operations were disposed of in prior periods. The $13.3 million income on discontinued operations is comprised primarily of a gain on sale of $11.9 million, net of income taxes of $1.4 million.

54

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 six months ended June 30, 2003, we recorded income on discontinued operations, net of income taxes of $61.6 million consisting of the results from our McClain, PERC, Cobee, Killingholme, NEO Landfill Gas, Inc., three NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC), Timber Energy Resources, Inc., Cahua and Energia Pacasmayo, Hsin Yu and LSP Energy projects. The $61.6 million income from discontinued operations is due primarily to the $191.2 million net gain recognized on the completion of the sale of our interest in Killingholme, partially offset by asset impairment charges of $100.7 million related to our McClain facilities.

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 August 2, 2004, we had $1.725 billion in aggregate principal amount of 8% Second Priority Notes outstanding, $443.0 million principal amount outstanding under the term loan and $107.9 million remains available under the funded letter of credit facility. As of August 2, 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. On June 30, 2004, we had posted $17.8 million in collateral. As of August 2, 2004, we have posted $11.1 million in collateral in support of the swaps.

     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

55

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 (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 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, was paid by Xcel Energy on May 28, 2004. We used the proceeds from the Xcel Energy settlement to reduce our creditor pool obligation. On February 20, 2004, April 30, 2004 and May 28, 2004, we made payments to former creditors of $163.0 million, $328.5 million and $23.5 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 $64.7 million for the six months ended June 30, 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 June 30, 2004 our liquidity remains $1.4 billion and includes $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 $1.2 billion and includes $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 Six Months Ended			For the Six Months Ended
	June 30, 2004			June 30, 2003
	(In thousands)
Net cash provided by operating activities	$	317,357		$	24,032
Net cash provided by investing activities		1,558			27,517
Net cash used by financing activities		(85,672	)		(33,522	)

Net Cash Provided By Operating Activities

Reorganized NRG

     For the six months ended June 30, 2004, cash provided by operating activities was $317.4 million. This was primarily a result of net income after non-cash charges of $317.1 million and $640 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 six months ended June 30, 2003, cash provided by operating activities was $24.0 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.

56

Net Cash Provided By Investing Activities

Reorganized NRG

     For the six months ended June 30, 2004, cash provided by investment activities was $1.6 million. This was primarily due to proceeds from the sales of equity method investments and discontinued operations offset by ongoing capital improvement projects at our South Central and Northeast facilities.

Predecessor Company

     For the six months ended June 30, 2003, cash provided by investing activities was $27.5 million. This was primarily a result of cash proceeds received upon the sale of investments and reduced capital expenditures.

Net Cash Used By Financing Activities

Reorganized NRG

     For the six months ended June 30, 2004, cash used by financing activities was $85.7 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 six months ended June 30, 2003, cash used by financing activities was $33.5 million, resulting primarily from principal payments on short and long-term debt.

Off Balance-Sheet Arrangements

     As of June 30, 2004, we have not entered into any sale-leaseback or other financing structure that is designed to be off balance-sheet that would create liquidity, financing or incremental market risk or credit risk. However, 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 $250.4 million and $967.7 million as of June 30, 2004 and December 31, 2003, respectively. The decline was a result of sales of our interest in Calpine Cogeneration and Loy Yang and the amortization of remaining debt. 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 payable and receivable to/from affiliates and notes payable/receivable 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 June 30, 2004
Contractual Cash									After
Obligations	Total		Short Term		2-3 Years		4-5 Years		5 Years
	(In thousands)
Long-term debt	$	3,491,817	$	34,132	$	541,708	$	85,620	$	2,830,357
Capital lease obligations		526,985		62,253		122,439		60,114		282,179
Operating leases		47,522		9,224		15,524		7,840		14,934
Total contractual cash obligations	$	4,066,324	$	105,609	$	679,671	$	153,574	$	3,127,470

57

	Amount of Commitment Expiration per Period as of June 30, 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		154,572		154,572		—		—		—
Cash collateral calls		—		—		—		—		—
Guarantees of subsidiaries		511,066		600		20,418		12,500		477,548
Guarantees of NRG PMI obligations		38,500		10,000		5,000		—		23,500
Total commercial commitments	$	704,138	$	165,172	$	25,418	$	12,500	$	501,048

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. This instrument was designated as a cash flow hedge under SFAS No. 133 as of April 1, 2004. As a result, subsequent changes to fair value were recorded as part of other comprehensive income. Changes in fair value prior to April 1, 2004 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. On June 30, 2004 and August 2, 2004, we had posted $17.8 million and $11.1 million, respectively, in collateral in support of the swaps. During the three months ended June 30, 2004, this transaction was designated as a fair value hedge; therefore, changes in fair value of the hedge instrument and hedged item were recorded in interest expense.

58

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.

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 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 June 30, 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 June 30, 2004, we had various interest rate swap agreements with notional amounts totaling approximately $1.6 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 June 30, 2004, we would have owed the counterparties approximately $56.2 million. Based on the investment grade rating of the counterparties, we believe that our exposure to credit risk due to nonperformance by the counterparties 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 June 30, 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 $9.5 million.

     At June 30, 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 $104.6 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.

59

     In the first quarter of 2004, we 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 implemented this change to increase the quality of our risk reporting and to meet industry standards. The key 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 new DVAR model is as follows:

		(In millions)
Quarter ending June 30, 2004 (Diversified)	$	39.3
Average		40.7
High		52.8
Low		35.4
Year ending December 31, 2003 (Diversified)		37.1
Average		45.7
High		53.0
Low		37.1

     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 counterparty of its contractual obligations. We actively manage our counterparty 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 counterparties, 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 period 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 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 a new Chief Risk Officer. To address transition issues, we have implemented a transition plan and established a staff retention bonus 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 consolidated 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

60

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.

     There have not been any changes in our internal control over financial reporting (as such term is defined in Rules 13a–15(f) and 15d–15(f) under the Exchange Act), during the fiscal quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II — OTHER INFORMATION

Item 1. Legal Proceedings

     For a discussion of material legal proceedings in which we were involved through June 30, 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 June 30, 2004:

     $181 million Loan Agreement dated November 30, 2001, as amended, between McClain 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

     On July 9, 2004, McClain completed the sale of its 77% interest in the McClain Generating Station to Oklahoma Gas & Electric. Proceeds of the sale were used to repay outstanding project debt under the secured term loan and working capital facility. McClain continues to be in bankruptcy and in default, with the expectation that it will file a liquidating plan of reorganization, settle all its outstanding obligations and be subsequently dissolved.

Item 5. Other Information

     On August 4, 2004, NRG’s stockholders ratified the engagement of KPMG LLP as our independent registered public accounting firm going forward.

     On August 4, 2004, the Board of Directors of NRG Energy approved and adopted the NRG Code of Conduct, which is attached hereto as Exhibit 14. The Code of Conduct is also available on our website at www.nrgenergy.com, or without charge upon written request directed to the Corporate Compliance Officer, NRG Energy, Inc., 901 Marquette Avenue, Minneapolis, Minnesota 55402. The Code of Conduct applies to all of NRG Energy’s directors, officers and employees. The Code of Conduct represents both the code of ethics for the principal executive officer, principal financial officer and principal accounting officer under the Securities and Exchange Commission rules and the code of business conduct and ethics under the New York Stock Exchange listing standards. We plan to disclose on our website any amendments to, or waivers from the Code of Conduct that are required to be publicly disclosed.

     On August 4, 2004, the Board of Directors of NRG Energy approved and adopted a minor, technical amendment to the Amended and Restated By-Laws which clarifies the language currently set forth therein. A marked copy of the Amended and Restated By-Laws is attached hereto as Exhibit 3.2.

Item 6. Exhibits and Reports on Form 8-K

(a) Exhibits

3.2	Amended and Restated By-Laws.
14	Code of Conduct.
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.

61

31.3	Certification of Controller pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification of Chief Executive Officer, Chief Financial Officer and Controller pursuant to Section 906 of the Sarbanes- Oxley Act of 2002, 18 U.S.C. Section 1350.

(b)	Reports on Form 8-K:
	NRG Energy filed or furnished reports on Form 8-K on the following dates during the quarter ended June 30, 2004:
	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.
	Form 8-K, furnished on May 11, 2004, to provide information under Item 12 regarding our financial and operating results for the quarter ended March 31, 2004.
	Form 8-K, filed on May 25, 2004, to provide information under Item 4 announcing that the Audit Committee engaged KPMG LLP as our independent registered public accounting firm.

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, or 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 statements. 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 successfully and timely close transactions 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;

62

• 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;

63

• 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.

64

Confidential Draft Document for Discussion Purposes only

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 Officer)

/s/ JAMES INGOLDSBY

James Ingoldsby,

Vice President and Controller

(Principal Accounting Officer)

Date: August 9, 2004

65

Confidential Draft Document for Discussion Purposes only

Exhibit Index

Exhibits

3.2	Amended and Restated By-Laws.
14	Code of Conduct.
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.
31.3	Certification of Controller pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32	Certification of Chief Executive Officer, Chief Financial Officer and Controller pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, 18 U.S.C. Section 1350.

66