NRG ENERGY INC - 10-Q Quarterly Report

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

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



For the quarterly period ended: September 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 (Address of principal executive offices)		55402 (Zip Code)

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

(Former name, former address and former fiscal year, if changed since last report)

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

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 November 2, 2004, there were 100,008,053 shares of common stock outstanding.

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)


	Reorganized			Predecessor			Reorganized			Predecessor
	NRG			Company			NRG			Company
	Three Months						Nine Months
	Ended						Ended
	September 30,			September 30,			September 30,			September 30,
	2004			2003			2004			2003
	(In thousands, except for per share amounts)
Operating Revenues
Revenues from majority-owned operations	$	606,663		$	570,701		$	1,780,551		$	1,507,186

Operating Costs and Expenses
Cost of majority-owned operations		381,010			384,386			1,116,021			1,142,976
Depreciation and amortization		51,373			56,510			159,547			179,225
General, administrative and development		54,307			34,420			136,445			122,052
Other charges
Legal settlement		—			396,000			—			396,000
Corporate relocation charges		5,713			—			12,474			—
Reorganization items		(5,245	)		20,698			(1,656	)		27,032
Restructuring and impairment charges		40,507			6,252			42,183			298,019

Total operating costs and expenses		527,665			898,266			1,465,014			2,165,304

Operating Income/(Loss)		78,998			(327,565	)		315,537			(658,118	)

Other Income (Expense)
Minority interest in (earnings) losses of consolidated subsidiaries		128			—			(581	)		—
Equity in earnings of unconsolidated affiliates		53,373			63,272			117,187			155,758
Write downs and gains/(losses) on sales of equity method investments		(13,524	)		12,310			(14,057	)		(136,717	)
Other income, net		5,502			7,300			17,210			10,118
Interest expense		(66,883	)		(34,424	)		(226,254	)		(294,460	)

Total other income (expense)		(21,404	)		48,458			(106,495	)		(265,301	)

Income/(Loss) From Continuing Operations Before Income Taxes		57,594			(279,107	)		209,042			(923,419	)
Income Tax Expense		14,264			5,437			64,866			42,779

Income/(Loss) From Continuing Operations		43,330			(284,544	)		144,176			(966,198	)
Income/(Loss) From Discontinued Operations, net of Income Taxes		10,891			(250	)		23,304			60,371

Net Income/(Loss)	$	54,221		$	(284,794	)	$	167,480		$	(905,827	)

Weighted Average Number of Common Shares Outstanding — Basic		100,101						100,066
Income From Continuing Operations per Weighted Average Common Share — Basic	$	0.43					$	1.44
Income From Discontinued Operations per Weighted Average Common Share — Basic		0.11						0.23

Net Income per Weighted Average Common Share — Basic	$	0.54					$	1.67

Weighted Average Number of Common Shares Outstanding — Diluted		100,616						100,328
Income From Continuing Operations per Weighted Average Common Share — Diluted	$	0.43					$	1.44
Income From Discontinued Operations per Weighted Average Common Share — Diluted		0.11						0.23

Net Income per Weighted Average Common Share — Diluted	$	0.54					$	1.67

See notes to consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (REORGANIZED COMPANY)
(Unaudited)


	September 30,		December 31,
	2004		2003
	(In thousands, except for
	share data)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases	$	100,105	$	801,229
Short-term debt		—		19,019
Accounts payable — trade		115,270		158,646
Accounts payable — affiliates		5,301		3,092
Accrued taxes		—		16,095
Accrued property, sales and other taxes		13,672		22,301
Accrued salaries, benefits and related costs		33,362		19,330
Accrued interest		65,011		8,982
Derivative instruments valuation		18,038		429
Creditor pool obligation		25,000		540,000
Other bankruptcy settlement		220,492		220,000
Other current liabilities		127,073		102,860
Current liabilities — held for sale		6,855		—
Current liabilities — discontinued operations		1,752		114,198

Total current liabilities		731,931		2,026,181

Other Liabilities
Long-term debt and capital leases		3,511,231		3,327,782
Deferred income taxes		143,129		149,493
Postretirement and other benefit obligations		113,640		105,946
Derivative instruments valuation		140,787		153,503
Other long-term obligations		385,496		480,937
Non-current liabilities — held for sale		555,546		—
Non-current liabilities — discontinued operations		1,081		558,885

Total non-current liabilities		4,850,910		4,776,546

Total Liabilities		5,582,841		6,802,727

Minority Interest		5,592		5,004
Commitments and Contingencies
Stockholders’ Equity
Serial Preferred Stock; 10,000,000 shares authorized, none issued and outstanding at September 30, 2004 and December 31, 2003		—		—
Common stock; $.01 par value; 500,000,000 shares authorized; 100,008,053 shares at September 30, 2004 and 100,000,000 shares at December 31, 2003 issued and outstanding		1,000		1,000
Additional paid-in capital		2,413,962		2,403,429
Retained earnings		178,505		11,025
Accumulated other comprehensive income		3,684		21,802

Total stockholders’ equity		2,597,151		2,437,256

Total Liabilities and Stockholders’ Equity	$	8,185,584	$	9,244,987

See notes to consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Reorganized			Predecessor
	NRG			Company
	Nine Months Ended
	September 30,
	2004			2003
	(In thousands)
Cash Flows from Operating Activities
Net income/(loss)	$	167,480		$	(905,827	)
Adjustments to reconcile net income/(loss) to net cash provided by operating activities
Distributions less than equity in earnings of unconsolidated affiliates		(13,703	)		(47,500	)
Depreciation and amortization		164,872			211,201
Amortization of debt issuance costs		22,440			14,306
Amortization of debt discount		15,685			—
Deferred income taxes		67,655			18,502
Minority interest		1,961			2,010
Unrealized gains on derivatives		(33,232	)		(12,500	)
Asset impairment		42,183			353,871
Write downs and losses on sales of equity method investments		14,057			136,531
Gain on sale of discontinued operations		(29,924	)		(217,920	)
Amortization of power contracts and emission credits		42,822			—
Reserve for note and interest receivable		4,572			—
Cash provided (used) by changes in certain working capital items
Accounts receivable		(29,480	)		(103,377	)
Xcel Energy settlement receivable		640,000			—
Accrued taxes		(45,555	)		(16,495	)
Inventory		(27,586	)		12,314
Prepayments and other current assets		24,436			(28,748	)
Accounts payable		(54,611	)		618,099
Accounts payable — affiliates		4,271			36,571
Accrued property, sales and other taxes		(6,415	)		1,733
Accrued salaries, benefits and related costs		22,291			(10,605	)
Accrued interest		45,625			129,585
Other current liabilities		(486,084	)		(118,365	)
Cash provided by changes in other assets and liabilities		41,661			47,929

Net Cash Provided by Operating Activities		595,421			121,315

Cash Flows from Investing Activities
Proceeds on sale of equity method investments		29,693			102,546
Proceeds on sale of discontinued operations		246,498			1,011
Proceeds on sales of subsidiaries		—			1,000
Investments in equity method investments and projects		(672	)		(369	)
Decrease in notes receivable, net		36,609			9,450
Capital expenditures		(78,293	)		(85,635	)
Increase in restricted cash and trust funds		(23,029	)		(188,127	)

Net Cash Provided (Used) by Investing Activities		210,806			(160,124	)

Cash Flows from Financing Activities
Proceeds from issuance of long-term debt, net		531,207			43,797
Deferred debt issuance costs		(8,497	)		(17,843	)
Principal payments on short and long-term debt		(750,343	)		(50,073	)

Net Cash Used by Financing Activities		(227,633	)		(24,119	)

Change in Cash from Discontinued Operations		(22,527	)		31,309
Effect of Exchange Rate Changes on Cash and Cash Equivalents		(2,507	)		(52,537	)

Net Increase (Decrease) in Cash and Cash Equivalents		553,560			(84,156	)
Cash and Cash Equivalents at Beginning of Period		551,223			360,860

Cash and Cash Equivalents at End of Period	$	1,104,783		$	276,704

See notes to consolidated financial statements.

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, the procurement of fuel and transportation services and the marketing of energy, capacity and related products in the United States and internationally. NRG Energy has a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels. NRG Energy seeks to maximize operating income through the effective procurement and trading of fuel supplies and transportation related services, and the marketing and trading of energy, capacity and ancillary services into spot, intermediate and long-term markets.

From May 14 to December 23, 2003, we and a number of our subsidiaries undertook a comprehensive reorganization and restructuring under Chapter 11 of the United States Bankruptcy Code. With the exception of the subsidiaries that remain in bankruptcy to effect their liquidation, we have completed our Chapter 11 process.

As of September 30, 2004, we owned interests in 53 power projects in five countries having an aggregate net generation capacity of approximately 16,800 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, approximately 750 MW of southwest Connecticut generation capacity and 575 MW of capacity in southern California. We also own approximately 2,500 MW of capacity in the South Central region of the United States, with approximately 1,900 MW of that capacity supported by long-term power purchase agreements. Our assets in the West Coast region of the United States consist of approximately 1,300 MW of capacity with the majority of such capacity owned via our 50% interest in West Coast Power LLC, or West Coast Power. Our assets in the West Coast region are supported by a power purchase agreement with the California Department of Water Resources that expires on December 31, 2004. One-year term “reliability must-run contracts” with the California Independent System Operator for approximately 575 MW in the San Diego area have been renewed for 2005. Approximately 265 MW of capacity at the Long Beach generating facility will be retired at year-end 2004.

Our principal domestic generation assets consist of a diversified mix of natural gas-, coal- and oil-fired facilities, representing approximately 43%, 29% and 28% 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 operate substantially all of our generating assets, including the West Coast Power plants.

We perform our own power marketing which is focused on maximizing the value of our North American assets through the pursuit of asset-focused power and fuel marketing and trading activities in the spot, intermediate and long-term markets. Our principal objectives are the management and mitigation of commodity market risk, the reduction of cash flow volatility over time, the protection and acquisition of the full market value of the asset base and adding incremental value by using market knowledge to effectively trade our natural positions. Additionally, we work with markets, independent system operators and regulators to design markets that provide adequate long-term compensation for existing generation assets and attract the investment required to meet growth needs. West Coast Power has arranged for power marketing and fuel management with affiliates of our partner, Dynegy, Inc.

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. We are in the process of moving our corporate headquarters to Princeton, New Jersey. Our Internet website is http://www.nrgenergy.com. Our recent annual reports, quarterly reports, current reports and other periodic filings are available free of charge through our Internet website.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation

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

Between May 14, 2003 and December 5, 2003, we operated as a debtor in possession under the supervision of the Bankruptcy Court. Our financial statements for reporting periods within that timeframe were prepared in accordance with the provisions of 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 as amended 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 as amended. 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 September 30, 2004, the results of our operations and stockholders’ equity/(deficit) for the three and nine months ended September 30, 2004 and 2003, and our cash flows for the nine months ended September 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

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.

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) from 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.

For the three and nine months ended September 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, LSP Energy (Batesville) and four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC). For the three and nine months ended September 30, 2003, discontinued operations included our NRG McClain, PERC, Cobee, Killingholme Power Limited, NEO Landfill Gas, Inc., or NLGI; seven NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC), Timber Energy Resources, Inc., or TERI; Cahua and Energia Pacasmayo, Hsin Yu and LSP Energy (Batesville) projects.

Summarized results of operations of discontinued operations were as follows:


	Reorganized NRG		Predecessor Company			Reorganized NRG		Predecessor Company
	Three Months Ended		Three Months Ended			Nine Months Ended		Nine Months Ended
	September 30, 2004		September 30, 2003			September 30, 2004		September 30, 2003
	(In thousands)
Operating revenues	$	6,243	$	76,127		$	108,428	$	212,627
Operating and other expenses		5,843		75,869			106,527		338,689

Pretax income/(loss) from operations of discontinued components		400		258			1,901		(126,062	)
Income tax expense (benefit)		—		(116	)		986		1,671

Income/(loss) from operations of discontinued components		400		374			915		(127,733	)
Disposal of discontinued components — pre-tax gain/(loss), net		16,916		(624	)		30,223		188,104
Income tax expense		6,425		—			7,834		—

Disposal of discontinued components — gain/(loss), net		10,491		(624	)		22,389		188,104

Income/(loss) from discontinued operations, net of income taxes	$	10,891	$	(250	)	$	23,304	$	60,371

The assets and liabilities of the discontinued operations are reported in the balance sheets as of September 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 September 30, 2004, the NRG McClain project is included in the Wholesale Power Generation-Other North America classification and NEO Corporation is included in the All Other classification under the Alternative Energy category; all other projects have been sold as of September 30, 2004. As of December 31, 2003, the PERC, NRG McClain and LSP Energy (Batesville) projects are included in the Wholesale Power Generation — Other North America classification, the Cobee and Hsin Yu projects are included in the All Other classification under the Other International category and the NEO Corporation is included in the All Other classification under the Alternative Energy category.


	Wholesale
	Power
	Generation		All Other
	Other North		Alternative
September 30, 2004	America		Energy		Total
			(In thousands)
Cash	$	1,692	$	—	$	1,692
Restricted cash		1,350		—		1,350
Receivables, net		—		—		—
Inventory		—		—		—
Prepaids and other current assets		—		—		—

Current assets — discontinued operations	$	3,042	$	—	$	3,042

PP&E, net	$	—	$	—	$	—
Other non-current assets		—		—		—

Non-current assets — discontinued operations	$	—	$	—	$	—

Current portion of long-term debt	$	—	$	—	$	—
Accounts payable — trade		1,085		37		1,122
Accrued liabilities		630		—		630
Other current liabilities		—		—		—

Current liabilities — discontinued operations	$	1,715	$	37	$	1,752

Long-term debt	$	—	$	—	$	—
Other non-current liabilities		1,081		—		1,081

Non-current liabilities — discontinued operations	$	1,081	$	—	$	1,081


	Wholesale Power
	Generation		All Other
			Wholesale Power
			Generation
	Other North		Other		Alternative
December 31, 2003	America		International		Energy		Total
			(In thousands)
Cash	$	4,292	$	8,264	$	—	$	12,556
Restricted cash		60,292		—		—		60,292
Receivables, net		12,676		11,259		—		23,935
Inventory		8,722		3,538		—		12,260
Prepaids and other current assets		3,730		6,785		43		10,558

Current assets — discontinued operations	$	89,712	$	29,846	$	43	$	119,601

PP&E, net	$	487,753	$	75,250	$	—	$	563,003
Non-current deferred tax asset		—		31,469		—		31,469
Other non-current assets		14,764		9,730		4,207		28,701

Non-current assets — discontinued operations	$	502,517	$	116,449	$	4,207	$	623,173

Current portion of long-term debt	$	6,206	$	49,744	$	—	$	55,950
Accounts payable — trade		3,057		23,037		3,998		30,092
Accrued liabilities		13,182		757		—		13,939
Other current liabilities		8,248		5,947		22		14,217

Current liabilities — discontinued operations	$	30,693	$	79,485	$	4,020	$	114,198

Long-term debt	$	313,738	$	19,779	$	—	$	333,517
Minority interest		31,879		406		—		32,285
Other non-current liabilities		184,972		8,111		—		193,083

Non-current liabilities — discontinued operations	$	530,589	$	28,296	$	—	$	558,885

NEO Corporation — On September 30, 2004, we completed the sale of NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC to Algonquin Power of Canada. We received cash proceeds of $5.8 million for these wholly owned entities. The sale also included several equity investments (see Note 4). The sale resulted in a gain of approximately $6.0 million associated with the four wholly owned entities sold.

LSP Energy (Batesville) — On August 24, 2004, we completed the sale of our 100 percent interest in an 837 megawatt generating plant in Batesville, Mississippi to CEP Batesville Acquisition, LLC. CEP Batesville Acquisition, LLC assumed approximately $300 million of outstanding project debt. The transaction results in the elimination of $289 million in consolidated debt from NRG Energy’s balance sheet. In exchange for the sale, we received cash proceeds of $27.6 million. We recorded a gain of $11.0 million in the third quarter.

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 were used to repay outstanding project debt under the secured term loan and working capital facility. A loss of $3.0 million was recognized 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, which reached financial closing in April 2004. Upon completion of the transaction, we received net proceeds of $18.4 million, resulting in a gain of $3.2 million.

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.

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 $10.0 million, due to 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 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		Nine Months			Nine Months
	Ended			Ended		Ended			Ended
	September 30, 2004			September 30, 2003		September 30, 2004			September 30, 2003
				(In thousands)
Commonwealth Atlantic Limited
Partnership	$	(3,686	)	$	—	$	(3,686	)	$	—
James River Power LLC		(6,008	)		—		(6,008	)		—
NEO Corporation —2004		(3,830	)		—		(3,830	)		—
Calpine Cogeneration		—			—		735			—
Loy Yang		—			—		(1,268	)		(139,972	)
NEO Corporation — Minnesota Methane		—			—		—			(12,257	)
Kondapalli		—			—		—			519
ECKG		—			—		—			2,869
Mustang		—			12,310		—			12,124

Total write downs and gains/(losses) on sales of equity method investments	$	(13,524	)	$	12,310	$	(14,057	)	$	(136,717	)

Commonwealth Atlantic Limited Partnership (CALP) — In June 2004, we executed a sales agreement with Virginia Electric Power Company (VEPCO) to sell our 50% interest in CALP. During the third quarter of 2004, we recorded an impairment charge of approximately $3.7 million to write down the value of our investment in CALP to its fair value. We expect the sale to close in the fourth quarter of 2004.

James River Power LLC — In September 2004, we executed an agreement with Colonial Power Company LLC to sell all of our outstanding shares of stock in Capistrano Cogeneration Company, a wholly-owned subsidiary of NRG Energy which owns a 50% interest in James River Cogeneration Company. During the third quarter of 2004, we recorded an impairment charge of approximately $6.0 million to write down the value of our investment in James River to its fair value. The sale is expected to close in the fourth quarter of 2004.

NEO Corporation — 2004 — On September 30, 2004, we completed the sale of several NEO investments – Four Hills LLC, Minnesota Methane II LLC, NEO Montauk Genco LLC and NEO Montauk Gasco LLC to Algonquin Power of Canada. The sale also included four wholly owned NEO subsidiaries (see Note 3). We received cash proceeds of $6.1 million. The sale resulted in a loss of approximately $3.8 million attributable to the equity investment entities sold.

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 nine months ended September 30, 2004.

NEO Corporation — 2003 (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 resulting from the legal release of certain obligations. This resulted in an adjusted loss of $12.3 million for the nine months ended September 30, 2003.

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.

Mustang Station — On July 7, 2003, NRG Energy completed the sale of its 50% interest in Mustang Station, a 483 MW gas-fired combined cycle power generating plant located in Denver City, Texas, to EIF Mustang Holdings I, LLC. The sale resulted in net cash proceeds of approximately $13.3 million and a net gain of approximately $12.1 million.

Note 5 —Assets Held for Sale

Kendall — On September 13, 2004, we reached an agreement for the sale of our Kendall generating plant to an affiliate of LS Power Associates, L.P. We have the right to reacquire a 40% interest in the plant within a 10-year period, for a nominal amount. The transaction will result in the deconsolidation of the plant and the debt associated with the project at that time. Approximately $446.6 million of Kendall project debt has been reclassified from long-term debt to non-current liabilities held for sale on the accompanying balance sheet as of September 30, 2004. In addition, NRG Energy will receive $1 million in cash proceeds. The transaction is expected to close in the fourth quarter of 2004. We have reclassified the assets and liabilities of Kendall to the held for sale category on the accompanying balance sheet as of September 30, 2004. Given our right to reacquire a 40% interest in the project, the transaction is being treated as a partial sale for accounting purposes. The transaction resulted in a third quarter non-cash loss of $24.5 million recorded in the restructuring and impairment charges line on the consolidated statement of operations.

Note 6 — Corporate Relocation Charges

We expect to incur $25.2 million of expenses in connection with corporate relocation charges. Relocating, recruiting and other employee-related transition costs are expected to be approximately $11.8 million and will be expensed as incurred. These costs and cash payments are expected to be incurred through first quarter of 2005. Severance and termination benefits of $8.3 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			September 30,
	2003		Charges		Payments			2004
			(In thousands)
Employee related transition costs	$	—	$	5,295	$	(5,295	)	$	—
Severance and termination benefits		—		6,112		(1,420	)		4,692
Lease termination costs		—		1,067		(163	)		904

Total	$	—	$	12,474	$	(6,878	)	$	5,596

As of September 30, 2004, the restructuring liability was $5.6 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 All Other — Other segment, in the corporate relocation charges line on the consolidated statement of operations.

Note 7 —Other Charges

Other 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		Nine Months Ended			Nine Months Ended
	September 30, 2004			September 30, 2003		September 30, 2004			September 30, 2003
				(In thousands)
Legal settlement	$	—		$	396,000	$	—		$	396,000
Reorganization items		(5,245	)		20,698		(1,656	)		27,032
Restructuring charges		—			294		—			68,455
Impairment charges		40,507			5,958		42,183			229,564

Total	$	35,262		$	422,950	$	40,527		$	721,051

Legal settlement – During the third quarter of 2003, we recorded $396.0 million in connection with the resolution of an arbitration claim asserted by FirstEnergy Corp. As a result of this resolution, FirstEnergy retained ownership of the Lake Plant Assets and received an allowed general unsecured claim of $396.0 million under NRG Energy’s Plan of Reorganization.

Reorganization items – We recorded a net credit of $5.2 million and $1.7 million related to reorganization items for the three and nine months ended September 30, 2004, respectively. These items relate primarily to the settlement of obligations recorded under Fresh Start. We incurred total reorganization expenses of approximately $20.7 million and $27.0 million for the three and nine months ended September 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 $0.3 million and $68.5 million for the three and nine months ended September 30, 2003, respectively. These costs consist of employee separation costs and advisor fees.

Impairment charges – In accordance with the guidelines of SFAS No. 144, certain events lead to the review of the recoverability of some of our long-lived assets. As a result of this review, we recorded $40.5 million and $42.2 million in impairment charges for the three and nine months ended September 30, 2004, respectively, and $6.0 million and $229.6 million for the three and nine months ended September 30, 2003, respectively, which included the following:

Note 9 — Property, Plant and Equipment

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


	September 30, 2004			December 31, 2003
	(In thousands)
Facilities and equipment	$	3,289,590		$	3,732,391
Land and improvements		130,053			134,888
Office furnishings and equipment		19,856			18,186
Construction in progress		68,135			139,171

Total property, plant and equipment		3,507,634			4,024,636
Accumulated depreciation		(156,643	)		(11,800	)

Net property, plant and equipment	$	3,350,991		$	4,012,836

Note 10 — Intangible Assets

Reorganized NRG

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

Power sale agreements will be amortized as a reduction to revenue over the terms and conditions of each contract. The weighted average remaining amortization period is 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 nine months ended September 30, 2004 was approximately $10.9 million and $40.4 million, respectively. The annual aggregate amortization for each of the five succeeding years, starting with 2004, is expected to approximate $49.1 million in 2004, $31.2 million in year two, $25.3 million in each of years three and four, and $19.2 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 nine months ended September 30, 2004, we reduced our deferred tax valuation allowance by $65.1 million (see Note 17) and recorded a corresponding reduction of $56.3 million related to our intangible assets at our wholly owned subsidiaries. The remaining $8.8 million was recorded as a reduction to our intangible asset related to our equity investments (see Note 12). 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 $9.7 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
	Agreements			Allowances			Total
				(In thousands)
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		(5,362	)		(50,894	)		(56,256	)
Other adjustments		—			(9,694	)		(9,694	)
Amortization		(25,544	)		(14,837	)		(40,381	)

Balance as of September 30, 2004	$	27,937		$	298,093		$	326,030

Predecessor Company

We had intangible assets of $26.8 million at September 30, 2003, that were not amortized and consisted of goodwill. We also had intangible assets of $44.2 million at September 30, 2003, that were amortized and consisted of service contracts. Aggregate amortization expense recognized for the three and nine months ended September 30, 2003 was approximately $1.0 million and $3.0 million, respectively.

Note 11 — 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 Wholesale Power Generation segments related to our North America projects in the South Central region, the Northeast region, Australia, and within our All Other segment, our Non-Generation and Alternative Energy 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 of the asset retirement obligation for the nine months ended September 30, 2004, which is included in other long-term obligations in the consolidated balance sheet.


			Accretion for the
	Beginning Balance		Nine Months Ended		Ending Balance
Description	December 31, 2003		September 30, 2004		September 30, 2004
			(In thousands)
South Central Region	$	2,638	$	137	$	2,775
Northeast Region		11,750		604		12,354
Australia		9,438		1,142		10,580
Non-Generation		1,334		69		1,403
Alternative Energy		834		44		878

Total	$	25,994	$	1,996	$	27,990

Note 12 — 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 nine months ended September 30, 2004, we recorded equity earnings of $17.2 million and $45.1 million, respectively, for West Coast Power after adjustments for the reversal of $3.7 million and $11.3 million, respectively, of project level depreciation expense, offset by a decrease in earnings related to $28.1 million and $89.7 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 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 $8.8 million as a result of allocating the reduction of our tax valuation allowance to our intangible assets (see Notes 10 and 17). 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				Nine Months Ended
	September 30,		September 30,		September 30,		September 30,
	2004		2003		2004		2003
			(In millions)
Operating revenues	$	364	$	308	$	962	$	834
Operating income	$	83	$	67	$	247	$	204
Net income (pre-tax)	$	83	$	74	$	247	$	205

Financial Position


	September 30,		December 31,
	2004		2003
	(In millions)
Current assets	$	366	$	257
Other assets		430		454

Total assets	$	796	$	711

Current liabilities	$	73	$	55
Other liabilities		8		8
Equity		715		648

Total liabilities and equity	$	796	$	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 entered into a definitive, comprehensive settlement which FERC approved on October 25, 2004.

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 September 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 18.

Note 13 — 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 (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.

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 September 30, 2004 before income taxes:

Energy

Interest

Foreign

Commodities

Rate

Currency

Total

(In thousands)

Accumulated OCI balance at June 30, 2004

(8,942

)

22,593

—

13,651

Unwound from OCI during period:

— Due to unwinding of previously deferred amounts

972

(3,307

)

—

(2,335

)

Fair value of hedge contracts

(1,920

)

(14,538

)

—

(16,458

)

Accumulated OCI balance at September 30, 2004

(9,890

)

4,748

—

(5,142

)

Losses expected to unwind from OCI during next 12 months

(13,130

)

(2,910

)

—

(16,040

)

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

Energy

Interest

Foreign

Commodities

Rate

Currency

Total

(In thousands)

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

9,756

3,751

170

13,677

Fair value of hedge contracts

(17,693

)

(603

)

—

(18,296

)

Accumulated OCI balance at September 30, 2004

(9,890

)

4,748

—

(5,142

)

Losses expected to unwind from OCI during next 12 months

(13,130

)

(2,910

)

—

(16,040

)

Gains of $2.3 million and losses of $13.7 million were reclassified from OCI to current period earnings during the three and nine months ended September 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 nine months ended September 30, 2004 we recorded losses in OCI of $16.5 million and $18.3 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 September 30, 2004 was an unrecognized loss of approximately $5.1 million. We expect $16.0 million of deferred net losses 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 September 30, 2004:

Reorganized NRG

Energy

Foreign

Commodities

Interest Rate

Currency

Total

(In thousands)

Revenue from majority-owned subsidiaries

(3,809

)

—

(3,809

)

Equity in earnings of unconsolidated affiliates

14,095

(215

)

—

13,880

Cost of operations

2,097

—

2,097

Total statement of operations impact before tax

12,383

(215

)

—

12,168

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 nine months ended September 30, 2004:

Reorganized NRG

Energy

Foreign

Commodities

Interest Rate

Currency

Total

(In thousands)

Revenue from majority-owned subsidiaries

3,659

—

3,659

Equity in earnings of unconsolidated affiliates

22,601

414

—

23,015

Cost of operations

465

—

465

Interest expense

—

411

—

411

Total statement of operations impact before tax

26,725

825

—

27,550


	Predecessor NRG
	Energy					Foreign
	Commodities			Interest Rate		Currency		Total
	(In thousands)
Revenue from majority-owned subsidiaries	$	(3,448	)	$	—	$	—	$	(3,448	)
Equity in earnings of unconsolidated affiliates		1,440			6,461		—		7,901
Cost of operations		1,769			—		—		1,769
Interest expense		—			24,638		—		24,638

Total statement of operations impact before tax	$	(239	)	$	31,099	$	—	$	30,860


	Predecessor NRG
	Energy						Foreign
	Commodities			Interest Rate			Currency		Total
	(In thousands)
Revenue from majority-owned subsidiaries	$	29,845		$	—		$	—	$	29,845
Equity in earnings of unconsolidated affiliates		5,173			6,172			—		11,345
Cost of operations		(7,386	)		—			—		(7,386	)
Other income		—			—			92		92
Interest expense		—			(20,970	)		—		(20,970	)

Total statement of operations impact before tax	$	27,632		$	(14,798	)	$	92	$	12,926

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 occurred on commodity cash flow hedges during the three and nine months ended September 30, 2004 and 2003.

During the three and nine months ended September 30, 2004, our pre-tax earnings were increased by an unrealized gain of $12.4 million and $26.7 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

During the three and nine months ended September 30, 2003, our pre-tax earnings were decreased by an unrealized loss of $0.2 million and increased by an unrealized gain of $27.6 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133.

During the three and nine months ended September 30, 2004, we reclassified losses of $1.0 million and $9.8 million, respectively, from OCI to current period earnings and expect to reclassify approximately $13.1 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

At September 30, 2004, we had hedge and non-hedge energy related commodities financial instruments extending through December 2018.

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 occurred on interest rate swaps that qualify as hedges during the three and nine months ended September 30, 2004.

During the three and nine months ended September 30, 2004, pre-tax earnings were decreased by an unrealized loss of $0.2 million and increased by an unrealized gain of $0.8 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. One of these instruments is a $400 million swap to pay fixed, which was not designated as a hedge of the expected cash flows at March 31, 2004. As of April 1, 2004, this instrument was designated as a cash flow hedge under SFAS No. 133. As a result, changes in value subsequent to April 1, 2004 are deferred and recorded as part of OCI. The remainder of the impact to the statement of operations from interest rate related derivative instruments is the result of changes in fair value of a non-hedge designated portion of one interest rate swap.

During the three and nine months ended September 30, 2003, pre-tax earnings were increased by an unrealized gain of $31.1 million and decreased by an unrealized loss of $14.8 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 nine months ended September 30, 2004, we reclassified gains of $3.3 million and losses of $3.8 million, respectively, from OCI to current period earnings and expect to reclassify approximately $2.9 million of deferred losses to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

At September 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 occurred on foreign currency cash flow hedges during the three and nine months ended September 30, 2004 and 2003.

During the three and nine months ended September 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 nine months ended September 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 September 30, 2004, no amounts were reclassified from OCI to current period earnings related to foreign currency hedging. During the nine months ended September 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 14 — 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.

As of September 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.

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 NRG Power Marketing, Inc., or 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 September 30, 2004, the interest rate on the term loan was 5.93%, 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 September 30, 2004, the $250.0 million letter of credit facility was fully funded and reflected as a funded letter of credit on the September 30, 2004 balance sheet. As of September 30, 2004, $152.5 million in letters of credit had been issued under this facility, leaving $97.5 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 September 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.

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 September 30, 2004 and as of November 2, 2004, we had no collateral posted.

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

LSP-Kendall Energy LLC

On September 13, 2004, we reached an agreement for the sale of our Kendall generating plant to an affiliate of LS Power Associates, L.P. We have the right to reacquire a 40% interest in the plant within a 10-year period, for a nominal amount. The sale transaction will result in the deconsolidation of the plant and the debt associated with the project at that time. Given our right to reacquire a 40% interest in the project, the transaction is being treated as a partial sale for accounting purposes. Consequently, $446.6 million of Kendall project debt has been reclassified from long-term debt to non-current liabilities – held for sale on the accompanying balance sheet as of September 30, 2004.

Itiquira Energetica S.A.

On July 15, 2004, Itiquira Energetica S. A., an indirectly wholly owned subsidiary of ours, executed a long-term financing arrangement with União de Bancos Brasileiros S.A. (“Unibanco”) for a 55 million Brazilian reals term loan maturing in January 2012. The facility bears a floating interest rate and amortizes on a schedule that is indexed to certain foreign exchange rates. The facility replaces a revolving loan undertaken with Unibanco which was classified as short-term debt on our balance sheet as of December 31, 2003. The current facility is classified as long-term debt as of September 30, 2004.

Note 15 — Earnings Per Share

Basic earnings per common share were computed by dividing net income by the weighted average number of common 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		Nine Months Ended
	September 30, 2004		September 30, 2004
	(In thousands, except per share data)
*Basic earnings per share*
Numerator:
Income from continuing operations	$	43,330	$	144,176
Income from discontinued operations, net of income taxes		10,891		23,304

Net income	$	54,221	$	167,480

Denominator:
Weighted average number of common shares outstanding		100,101		100,066
Income from continuing operations per weighted average common share	$	0.43	$	1.44
Income from discontinued operations, net of income taxes per weighted average common share		0.11		0.23

Net income per weighted average common share — basic	$	0.54	$	1.67


	Reorganized NRG
	Three Months Ended		Nine Months Ended
	September 30, 2004		September 30, 2004
	(In thousands, except per share data)
*Diluted earnings per share*
Numerator
Income from continuing operations	$	43,330	$	144,176
Income from discontinued operations, net of income taxes		10,891		23,304

Net income	$	54,221	$	167,480

Denominator:
Weighted average number of common shares outstanding		100,101		100,066
Incremental shares attributable to the assumed exercise of outstanding stock options (treasury stock method)		19		—
Incremental shares attributable to the issuance of nonvested restricted stock units (treasury stock method)		496		262

Total dilutive shares		100,616		100,328

Income from continuing operations per weighted average common share – diluted	$	0.43	$	1.44
Income from discontinued operations, net of income taxes per weighted average common share – diluted		0.11		0.23

Net income per weighted average common share – diluted	$	0.54	$	1.67

For the three and nine months ended September 30, 2004, options totaling 15,000 and 647,751, respectively, have been excluded from the dilutive calculation as their exercise prices exceeded the average market price of the common shares during the three months and nine months ended September 30, 2004, respectively, and therefore the effect would be anti-dilutive.

Stock options: During the period January 1, 2004 through September 30, 2004, we issued stock option grants for 322,000 shares of common stock under the Long-Term Incentive Plan at fair values between $19.90 and $27.27. These options have a three-year graded vesting schedule. Compensation expense recorded under the stock option grants for the three and nine months ended September 30, 2004 was approximately $1.7 million and $4.8 million, respectively.

Restricted stock units: During the period January 1, 2004 through September 30, 2004, we issued 711,600 Restricted Stock Units, or RSUs, under the Long-Term Incentive Plan at fair values between $19.90 and $27.72 per unit. These units cliff vest in three years. Compensation expense recorded under the RSUs for the three and nine months ended September 30, 2004 was approximately $1.5 million and $3.7 million, respectively. For purposes of computing earnings per share, nonvested RSUs are not considered outstanding for purposes of computing basic earnings per share; however, these units are included in the denominator for purposes of computing diluted earnings per share under the treasury stock method.

Deferred stock units: During the period January 1, 2004 through September 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 nine months ended September 30, 2004 was approximately $0.0 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 16 — 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 operations. In addition, we have refined the reporting of the remaining portions of our business. As a result of these changes, we have retroactively recast our prior period disclosures in a consistent manner.

We conduct the majority of our business within five reportable operating segments. All of our other operations are presented under the “All Other” category. Our reportable operating segments consist of Wholesale Power Generation – Northeast, Wholesale Power Generation – South Central, Wholesale Power Generation – West Coast, Wholesale Power Generation – Other North America and Wholesale Power Generation – Australia. These reportable segments are distinct components with separate operating results and management structures in place. Included in the All Other category are our Wholesale Power Generation – Other International operations, our Alternative Energy operations, our Non – Generation operations and an Other component which includes primarily our corporate charges (primarily interest expense) that have not been allocated to the reportable segments and the remainder of our operations which are not significant. We have presented this detail within the All Other category, as we believe that this information is important to a full understanding of our business.


	Reorganized NRG
	Three Months Ended September 30, 2004
	Wholesale Power Generation
	(In thousands)
				South					Other North
	Northeast			Central		West Coast			America			Australia
Operating Revenues	$	321,097		$	107,140	$	3,413		$	40,912		$	47,406
Corporate relocation charges		3			—		—			—			—
Reorganization items		(134	)		11		—			(34	)		—
Restructuring and impairment charges		247			740		—			24,520			—
Equity in earnings of unconsolidated affiliates		—			—		19,188			14,114			2,060
Write downs and gains/(losses) on sales of equity method investments		—			—		—			(9,694	)		—
Income/(Loss) From Continuing Operations Before Income Taxes		87,821			14,407		18,180			(19,357	)		2,256
Income Tax Expense (Benefit)		—			—		(245	)		(4,304	)		(1,861	)
Income/(Loss) From Continuing Operations		87,821			14,407		18,425			(15,053	)		4,117
Income/(Loss) From Discontinued Operations, net of Income Taxes		—			—		—			7,351			—
Net Income/(Loss)		87,821			14,407		18,425			(7,702	)		4,117
Balance Sheet Total Assets	$	2,036,976		$	1,138,166	$	334,977		$	1,416,322		$	904,058

Reorganized NRG

Three Months Ended September 30, 2004

All Other

(In thousands)

Wholesale

Power

Generation

Other

Alternative

Non-

International

Energy

Generation

Other

Total

Operating Revenues

37,986

16,839

32,362

(492

)

606,663

Corporate relocation charges

—

5,710

5,713

Reorganization items

—

272

(5,360

)

(5,245

)

Restructuring and impairment charges

—

15,000

40,507

Equity in earnings of unconsolidated affiliates

18,336

(325

)

—

53,373

Write downs and gains/(losses) on sales of equity method investments

—

(3,830

)

—

(13,524

)

Income/(Loss) From Continuing Operations Before Income Taxes

26,666

(2,401

)

7,343

(77,321

)

57,594

Income Tax Expense (Benefit)

2,422

(2,028

)

497

19,783

14,264

Income/(Loss) From Continuing Operations

24,244

(373

)

6,846

(97,104

)

43,330

Income/(Loss) From Discontinued Operations, net of Income Taxes

—

3,540

—

10,891

Net Income/(Loss)

24,244

3,167

6,846

(97,104

)

54,221

Balance Sheet Total Assets

836,775

63,416

574,444

880,450

8,185,584


	Predecessor Company
	Three Months Ended September 30, 2003
	Wholesale Power Generation
	(In thousands)
			South					Other North
	Northeast		Central			West Coast		America			Australia
Operating Revenues	$	287,382	$	101,877		$	11,971	$	35,850		$	47,790
Reorganization items and legal settlement		515		741			—		—			—
Restructuring and impairment charges		9,327		—			—		422			518
Equity in earnings of unconsolidated affiliates		—		—			39,960		5,353			8,408
Write downs and gains/(losses) on sales of equity method investments		—		—			—		12,310			518
Income/(Loss) From Continuing Operations Before Income Taxes		18,581		(1,514	)		44,639		9,692			8,681
Income Tax Expense (Benefit)		2		—			1,362		1,846			(363	)
Income/(Loss) From Continuing Operations		18,579		(1,514	)		43,277		7,846			9,044
Income/(Loss) From Discontinued Operations, net of Income Taxes		—		—			—		(939	)		—
Net Income/(Loss)		18,579		(1,514	)		43,277		6,907			9,044
Balance Sheet Total Assets	$	2,513,724	$	1,375,012		$	488,404	$	2,597,831		$	624,385


	Predecessor Company
	Three Months Ended September 30, 2003
	All Other
	(In thousands)
	Wholesale
	Power
	Generation
	Other			Alternative			Non-
	International			Energy			Generation			Other			Total
Operating Revenues	$	38,182		$	17,989		$	32,622		$	(2,962	)	$	570,701
Reorganization items and legal settlement		—			—			—			415,442			416,698
Restructuring and impairment charges		(3,609	)		(1	)		—			(405	)		6,252
Equity in earnings of unconsolidated affiliates		8,774			777			—			—			63,272
Write downs and gains/(losses) on sales of equity method investments		(518	)		—			—			—			12,310
Income/(Loss) From Continuing Operations Before Income Taxes		21,657			2,847			6,277			(389,967	)		(279,107	)
Income Tax Expense (Benefit)		1,947			2,074			(130	)		(1,301	)		5,437
Income/(Loss) From Continuing Operations		19,710			773			6,407			(388,666	)		(284,544	)
Income/(Loss) From Discontinued Operations, net of Income Taxes		2,068			(1,380	)		—			1			(250	)
Net Income/(Loss)		21,778			(607	)		6,407			(388,665	)		(284,794	)
Balance Sheet Total Assets	$	1,480,740		$	88,386		$	338,085		$	667,449		$	10,174,016

Reorganized NRG

Nine Months Ended September 30, 2004

Wholesale Power Generation

(In thousands)

South

Other North

Northeast

Central

West Coast

America

Australia

Operating Revenues

926,666

304,902

1,020

91,334

146,428

Corporate relocation charges

—

Reorganization items

215

664

—

117

—

Restructuring and impairment charges

247

2,416

—

24,520

—

Equity in earnings of unconsolidated affiliates

—

49,885

16,415

8,766

Write downs and gains/(losses) on sales of equity method investments

—

(8,959

)

(1,268

)

Income/(Loss) From Continuing Operations Before Income Taxes

231,479

42,278

42,780

(29,827

)

10,378

Income Tax Expense (Benefit)

—

(3,560

)

(1,967

)

Income/(Loss) From Continuing Operations

231,479

42,278

42,688

(26,267

)

12,345

Income/(Loss) From Discontinued Operations, net of Income Taxes

—

8,284

—

Net Income/(Loss)

231,479

42,278

42,688

(17,983

)

12,345

Reorganized NRG

Nine Months Ended September 30, 2004

All Other

(In thousands)

Wholesale

Power

Generation

Other

Alternative

Non-

International

Energy

Generation

Other

Total

Operating Revenues

117,426

49,219

145,809

(2,253

)

1,780,551

Corporate relocation charges

—

12,470

12,474

Reorganization items and legal settlement

—

432

(3,084

)

(1,656

)

Restructuring and impairment charges

—

15,000

42,183

Equity in earnings of unconsolidated affiliates

41,696

425

—

117,187

Write downs and gains/(losses) on sales of equity method investments

—

(3,830

)

—

(14,057

)

Income/(Loss) From Continuing Operations Before Income Taxes

67,283

2,677

60,494

(218,500

)

209,042

Income Tax Expense (Benefit)

11,872

(2,020

)

1,097

59,352

64,866

Income/(Loss) From Continuing Operations

55,411

4,697

59,397

(277,852

)

144,176

Income/(Loss) From Discontinued Operations, net of Income Taxes

12,357

2,663

—

23,304

Net Income/(Loss)

67,768

7,360

59,397

(277,852

)

167,480


	Predecessor Company
	Nine Months Ended September 30, 2003
	Wholesale Power Generation
	(In thousands)
				South		Other North
	Northeast			Central		West Coast		America			Australia
Operating Revenues	$	728,246		$	298,804	$	18,344	$	72,590		$	130,214
Reorganization items and legal settlement		1,081			1,627		—		—			—
Restructuring and impairment charges		233,811			1,918		—		42,392			524
Equity in earnings of unconsolidated affiliates		—			—		103,801		10,260			15,881
Write downs and gains/(losses) on sales of equity method investments		—			—		—		12,124			(139,454	)
Income/(Loss) From Continuing Operations Before Income Taxes		(301,972	)		7,343		107,367		(89,641	)		(127,931	)
Income Tax Expense (Benefit)		2			—		37,806		3,469			(1,626	)
Income/(Loss) From Continuing Operations		(301,974	)		7,343		69,561		(93,110	)		(126,305	)
Income/(Loss) From Discontinued Operations, net of Income Taxes		—			—		—		(109,712	)		—
Net Income/(Loss)		(301,974	)		7,343		69,561		(202,822	)		(126,305	)


	Predecessor Company
	Nine Months Ended September 30, 2003
	All Other
	(In thousands)
	Wholesale
	Power
	Generation
	Other			Alternative			Non-
	International			Energy			Generation		Other			Total
Operating Revenues	$	111,287		$	49,657		$	104,492	$	(6,448	)	$	1,507,186
Reorganization items and legal settlement		—			—			—		420,324			423,032
Restructuring and impairment charges		(6,961	)		(1	)		26		26,310			298,019
Equity in earnings of unconsolidated affiliates		27,154			(1,338	)		—		—			155,758
Write downs and gains/(losses) on sales of equity method investments		2,870			(12,257	)		—		—			(136,717	)
Income/(Loss) From Continuing Operations Before Income Taxes		53,154			(6,432	)		19,039		(584,346	)		(923,419	)
Income Tax Expense (Benefit)		7,934			2,022			690		(7,518	)		42,779
Income/(Loss) From Continuing Operations		45,220			(8,454	)		18,349		(576,828	)		(966,198	)
Income/(Loss) From Discontinued Operations, net of Income Taxes		211,019			(25,276	)		—		(15,660	)		60,371
Net Income/(Loss)		256,239			(33,730	)		18,349		(592,488	)		(905,827	)

Note 17 — Income Taxes

The income tax provisions for the nine months ended September 30, 2004 and 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 nine months ended September 30, 2004 was $14.3 million and $64.9 million, respectively, compared to a tax expense of $5.4 million and $42.8 million, respectively, for the same periods in 2003. The tax expense for the nine months ended September 30, 2004 includes U.S. tax expense of $54.6 million and foreign tax expense of $10.3 million. The tax expense for the nine months ended September 30, 2003 includes U.S. tax expense of $36.1 million and foreign tax expense of $6.7 million.

For U.S. income tax purposes, the tax expense in 2004 is due to a reduction in deferred tax assets without a tax benefit for the corresponding reduction in valuation allowance. Due to the uncertainty of realization of deferred tax assets related to net operating losses and other temporary differences, our U.S. net deferred tax assets at December 5, 2003 were offset by a full valuation allowance of $1.3 billion in accordance with SFAS 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 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 nine months of 2004 and 2003 is due to the earnings in foreign jurisdictions.

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

We have assessed the likelihood that a substantial portion of our deferred tax assets relating to the net operating loss carryforwards would not be realized. This assessment included consideration of positive and negative factors, including our current financial position and results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. As a result of such assessment, we determined that it was more likely than not that the deferred tax assets related to our domestic net operating loss carryforwards would not be realized. A full valuation allowance was recorded against the net deferred tax assets including net operating loss carryforwards. We also determined that it is more likely than not that a substantial portion of the net operating loss generated in 2002 and 2003 could be determined to be capital in nature. Given that capital losses are of a different character than ordinary losses the likelihood of capital losses expiring unutilized is greater than that of ordinary net operating losses.

Note 18 — Commitments and Contingencies

Legal Issues

Set forth below is a description of our material legal proceedings. In addition to the matters described below, we are party to legal proceedings arising in the ordinary course of business. In management’s opinion, the disposition of these ordinary course matters will not materially adversely affect our financial condition, results of operations or cash flows.

Pursuant to the requirements of Statement of Financial Accounting Standards No. 5, “Accounting for Contingencies,” and related guidance, we record reserves for estimated losses from contingencies when information available indicates that a loss is probable and the amount of the loss is reasonably estimable. Because litigation is subject to inherent uncertainties and unfavorable rulings or developments could occur, there can be no certainty that we may not ultimately incur charges in excess of presently recorded reserves. A future adverse ruling or unfavorable development could result in future charges which could have a material adverse effect on NRG Energy’s consolidated financial position, results of operations or cash flows.

With respect to a number of the items listed below, management has determined that a loss is not probable or the amount of the loss is not reasonably estimable, or both. In some cases, management is not able to predict with any degree of substantial certainty the range of possible loss that could be incurred. Notwithstanding these facts, management has assessed each of these matters based on

current information and made a judgment concerning its potential outcome, considering the nature of the claim, the amount and nature of damages sought and the probability of success. Management’s judgment may, as a result of facts arising prior to resolution of these matters or other factors, prove inaccurate and investors should be aware that such judgment is made subject to the known uncertainty of litigation.

The descriptions below update, and should be read in conjunction with, the complete descriptions under “Note 24 Commitments and Contingencies” in NRG Energy’s Form 10-K for the year ended December 31, 2003, as amended, and under “Note 17 Commitments and Contingencies” in our Form 10-Q for the quarter ended June 30, 2004, as amended. For any matter previously disclosed in those Forms, if material changes have occurred since the filing of our Form 10-K, supplemental disclosures describing such changes appear below the heading for that matter. If no material changes to a matter previously disclosed in those Forms have occurred since the filing of our Form 10-K, no supplemental disclosures appear below its heading.

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.

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 sought rehearing which the Ninth Circuit denied on October 29, 2004.

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).

Plaintiff filed a notice of appeal, and the appeal was argued in June, 2004. Consistent with its July, 2004 decision in People of the State of California ex. rel. Bill Lockyer, described above, the Ninth Circuit on September 10, 2004 rejected plaintiff’s appeal, holding that plaintiff’s claims are barred by federal preemption and the filed-rate doctrine.

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).“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.

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

Jerry Egger, et al. v. Dynegy, Inc., et al., Case No. 809822, Superior Court of California, San Diego County (filed May 1, 2003).

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.

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. The complaint names West Coast Power and various Dynegy entities among the numerous defendants. The complaint 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 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 Dynegy 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.

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

This putative class action lawsuit was filed in late September, 2004 in California state court. The complaint names West Coast Power and various Dynegy entities among the numerous defendants. The complaint alleges violation of California Business & Professions Code § 16720 (the Cartwright Act) and Business & Professions Code § 17200, based on defendants’ alleged efforts to fix, raise, stabilize, maintain and manipulate retail natural gas prices in California at supra-competitive levels. The complaint seeks a determination of class action status, a trebling of unspecified damages, restitution, disgorgement and costs and attorneys’ fees. We cannot predict the likelihood of an unfavorable outcome at this time.

Nurserymen’s Exchange, Inc. v. Sempra Energy, et al., Superior Court of California, County of San Mateo, Case No. CIV442605; County of Alameda v. Sempra Energy, et al., Superior Court of California, County of Alameda, Case No. RG04182878; School Project for Utility Rate Reduction v. Sempra Energy, et al., Superior Court of California, County of Alameda, Case No. RG04180958

All three of these actions were filed in October, 2004, and each complaint names numerous defendants, including West Coast Power. Also named in each case are various Dynegy entities, including Dynegy Marketing and Trade, which each complaint asserts handled all of the administrative services and commodity related concerns of West Coast Power. Although NRG Energy, Inc. is not named as a defendant, each complaint refers to West Coast Power as a joint venture between us and an affiliate of defendant Dynegy Marketing and Trade. Each complaint alleges violations of California’s Cartwright Act (Business and Professions Code § 16700, et seq.) and unjust enrichment, asserting that defendants and unnamed co-conspirators engaged in an agreement, contract, combination, trust and/or conspiracy to create and maintain supra-competitive prices for retail natural gas sold in California. Specifically, each plaintiff alleges defendants’ and unnamed co-conspirators’ unlawful conduct included, among other things, manipulating industry price indices and engaging in so-called “churning” and “wash trades.” Each complaint seeks a trebling of unspecified damages, exemplary damages, civil penalties, a preliminary and permanent injunction, a constructive trust, restitution and costs and attorneys’ fees. We cannot predict the likelihood of an unfavorable outcome in these cases at this time.

In Re: Natural Gas Commodity Litigation, Master File No. 03 CV 6186(VM)(AJP), United States District Court for the Southern District of New York

West Coast Power and Dynegy Marketing and Trade are among numerous defendants accused of manipulating gas index publications and prices in violation of the Commodity Exchange Act, 7 U.S.C. § 1, et seq. (the “CEA”), in the following consolidated cases: Cornerstone Propane Partners, LP v. Reliant Energy Services, Inc., et al., Case No. 03 CV 6186 (S.D.N.Y. filed August 18, 2003); Calle Gracey v. American Electric Power Co., Inc., et al., Case No. 03 CV 7750 (S.D.N.Y. filed Oct. 1, 2003); Cornerstone Propane Partners, LP v. Coral Energy Resources, LP, et al., Case No. 03 CV 8320 (S.D.N.Y. filed Oct. 21, 2003); and Viola v. Reliant Energy Servs., et al., Case No. 03 CV 9039 (S.D.N.Y. filed Nov. 14, 2003). Plaintiffs, in their Amended Consolidated Class Action Complaint dated October 14, 2004, allege that West Coast Power, Dynegy Marketing and Trade and other energy companies engaged in an illegal scheme to inflate natural gas prices by providing false information to gas index publications, thereby manipulating the price. The Amended Complaint relies heavily on FERC and CFTC investigations into, and reports concerning, index-reporting manipulation in the energy industry. The Amended Complaint also alleges that Dynegy Marketing and Trade and certain other defendants sought to manipulate gas prices by engaging in so-called “wash trades” and other market gaming strategies. The plaintiffs seek class action status for their lawsuit, unspecified actual damages for violations of the CEA and costs and attorneys’ fees. Counsel for Dynegy Marketing and Trade is also defending West Coast Power in these proceedings. We cannot predict the likelihood of an unfavorable outcome at this time.

Fairhaven Power Company v. Encana Corporation, et. al., Case No. CIV-F-04-6256 (OWW/LJO), United States District Court, Eastern District of California

This putative class action lawsuit was filed in September, 2004 in federal district court in California. The complaint names West Coast Power and Dynegy Holding Co., Inc. among the numerous defendants. The complaint alleges violation of the federal Clayton and Sherman Acts, California’s Cartwright Act and Business and Professions Code section 17200, et seq., unjust enrichment and seeks imposition of a constructive trust. Specifically, plaintiff alleges defendants and co-conspirators conspired to fix prices in the California natural gas market by, among other things, providing false information to natural gas trade indices and engaging in so-called “wash trades,” as of result of which plaintiff and members of the putative class paid supra-competitive prices for natural gas. The complaint seeks a determination of class action status, a trebling of unspecified damages, statutory, punitive or exemplary damages, restitution, disgorgement, injunctive relief, a constructive trust and costs and attorneys’ fees. We cannot predict the likelihood of an unfavorable outcome at this time.

California Investigations

FERC — California Market Manipulation

On October 25, 2004, FERC approved the settlement.

Other FERC Proceedings

U.S. Attorney – Houston

U.S. Attorney – San Francisco

California State Senate Select Committee

CPUC

California Attorney General

NRG Energy Bankruptcy Cap on California Claims

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

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 reserves 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 NYISO’s 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 obliged 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 argued that FERC had the authority to order refunds in the case because NYISO’s 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 sought by 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 Energy entities which may be affected include NRG Power Marketing, Inc., Astoria Gas Turbine Power LLC and Arthur Kill Power LLC. Although non-NRG Energy-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

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

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.

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

Huntley Power LLC

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

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

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

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

Itiquira Energetica, S.A.

Expert testimony was presented at a hearing in August, 2004. Further expert testimony will be submitted at a final hearing which will take place in either November or early December of 2004. The court of arbitration has indicated that it will deliver a decision within 30 days of that final hearing. We cannot estimate the likelihood of an unfavorable outcome in this dispute.

CFTC Trading Inquiry

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. On July 23, 2004, we filed a motion with the bankruptcy court to enforce the injunction provisions of the NRG Energy plan of reorganization in order to preclude the CFTC’s Minnesota federal court action. On July 27, 2004, we filed with the Minnesota federal district court a motion to dismiss or, in the alternative, to transfer venue to the bankruptcy court. We cannot at this time predict the outcome of this matter.

General Electric Company and Siemens Westinghouse Turbine Purchase Disputes

In August, 2004, we executed with GE final settlement documentation resolving the disputed bankruptcy claims of GE and its subsidiaries. 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 Energy plan of reorganization, we have funded a disputed claims reserve for the satisfaction of certain general unsecured bankruptcy 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 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.

Regulatory Issues

New England

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.

The initial RMR agreement between ISO-NE and the Company covering Devon station units 7 and 8 terminated on September 30, 2003. 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 bearing and consolidated the case with other similar NRG Energy cases before a settlement judge. On September 21, 2004, FERC issued an order on the various rehearing motions finding that the rates as filed for this RMR agreement are just and reasonable. On October 1, 2004, Devon 7 was deactivated because it was no longer needed for reliability.

On November 2, 2004, ISO-NE filed with FERC a Settlement Agreement, which was supported by NRG Energy, the Connecticut Department of Public Utility Control, the Connecticut Office of Consumer Counsel and various NEPOOL market participants. If approved by FERC, the settlement would resolve all outstanding reliability-must-run (RMR) issues, with the exception of a true-up for the third party maintenance payments known as the “cost tracker”. Under the terms of the agreement, the RMR agreements and the “cost tracker” would terminate at the earlier of the implementation of a LICAP market or December 31, 2005. Under the settlement agreement, the average rate for Montville, Middletown and Devon 11-14 would be $89.2 million or an average of $5.34 per KW-month from January 17, 2004 through December 31, 2005 in lieu of the rates conditionally approved by FERC in its March 22, 2004 order. The rate for Devon 7 from June 7, 2004 through October 1, 2004 would be $12.4 million on an annual basis or $9.66 per KW-month. Third party maintenance expenses would be capped at $30 million for Devon 11-14, Middletown, Montville and Norwalk Harbor for the period of April 1, 2004 through December 31, 2005. NRG Energy would retain 35% of all infra marginal revenues received by Devon 11-14, Middletown and Montville. As of this date, FERC has not responded to the November 2, 2004 filing.

On September 1, 2004, ISO-NE filed its LICAP proposal with the FERC administrative law judge (ALJ). Under the ISO-NE’s proposal, separate capacity zones would exist for Southwest Connecticut and the rest of Connecticut. LICAP payments would be based on the availability of generating facilities in the real-time market for one hundred critical hours as determined by ISO-NE. On November 4, 2004, NRG Energy and other participants in the NEPOOL locational installed capacity (LICAP) case submitted testimony to FERC. In the testimony, NRG Energy asserted that the LICAP design proposed by ISO-NE was inadequate to insure reasonable compensation for generators and would not encourage entry by new generation. In the testimony, NRG Energy presented an alternative LICAP design which we believe would resolve the deficiencies of the ISO-NE’s proposal. A recommended decision by the FERC administrative law judge is expected on June 1, 2005.

Contractual Commitments

Rail Car Agreement - On August 23, 2004, PMI entered into an agreement with a vendor for the construction of 1,540 aluminum rail cars to be put into service for the transportation of Powder River Basin coal from Wyoming to NRG Energy’s coal burning generating plants. NRG Energy has the right to either purchase the rail cars outright for a value of $85.9 million or lease them from this vendor for lease term options ranging from 3 to 10 years. Delivery of the rail cars will commence in January 2005. At this time NRG Energy plans to lease rather than purchase these rail cars and is exploring lease terms with rail car leasing companies. It is anticipated that any lease arrangement would be accounted for as an operating lease.

Note 19 — 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 Energy on behalf of a directly or indirectly held majority-owned subsidiary. Due to the inter-company nature of such arrangements (NRG Energy 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.

We are directly liable for the obligations of certain of our project affiliates and other subsidiaries pursuant to guarantees relating to certain of their indebtedness, equity and operating obligations. In addition, in connection with the purchase and sale of fuel, emission credits and power generation products to and from third parties with respect to the operation of some of our generation facilities in the United States, we may be required to guarantee a portion of the obligations of certain of our subsidiaries.

As of September 30, 2004, our obligations pursuant to our guarantees of the performance, equity and indebtedness obligations of our subsidiaries were as follows:


Description	September 30, 2004
(Includes only quantifiable amounts)	(In thousands)
Guarantees of subsidiaries	$	526,336
Guarantees of NRG PMI obligations		42,100
Guarantees of NE Genco obligations		12,339
Cash collateral calls		—

Total	$	580,775

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


	Maximum Amount
Project or	(September 30, 2004)
Subsidiary	(In thousands)		Nature of Guarantee	Expiration	Triggering Event
Astoria/Arthur Kill	Indeterminate		Performance Under Asset Purchase Agreement	None stated	Non-performance
Batesville	$	250	Indemnity of Purchaser for Claims Relating to Sale	August 24, 2006	Non-payment
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	$	4,411	Fund Superannuation (Pension) Reserve	September 8, 2012	Credit agreement default
Flinders	$	50,953	Debt Service Reserve Guaranty	September 8, 2012	Credit agreement default
Flinders	$	60,098	Plant Removal and Site Remediation Obligation	Undetermined	Non-performance
Flinders	$	72,790	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	$	219,738	Guaranty of Obligation to Purchase Gas	None stated	Non-payment
Gladstone	$	23,752	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	$	26,408	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	$	8,603	Guarantee of Share Purchase Agreement	None stated	Non-performance
NEO	$	5,489	Guarantee of Obligations Under the Sale and Purchase Agreement	None stated	Non-performance
Newport	$	7,500	Executory Contract	Undetermined	Non-payment
Other	$	19,095	Various	Various	Various
PMI	$	42,100	Guarantee on behalf of NRG Power Marketing Inc. for various projects	Various	Non-performance
NE Genco	$	12,339	Guarantee on behalf of NRG Northeast Generating Co., LLC for various projects	December 31, 2025	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	$	580,775

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 20 — Benefit Plans and Other Postretirement Benefits

Reorganized NRG

Substantially all of our employees participate in defined benefit pension plans. We have initiated a new NRG Energy noncontributory, defined benefit pension plan effective January 1, 2004, with credit for service from December 5, 2003. In addition, we provide postretirement health and welfare benefits (health care and death benefits) for certain groups of our employees. Generally, these are groups that were acquired in recent years and for whom prior benefits are being continued (at least for a certain period of time or as required by union contracts). Cost sharing provisions vary by acquisition group and terms of any applicable collective bargaining agreements. We have contributed $1.0 million to the NRG Energy pension plans during the nine months ended September 30, 2004. We expect to contribute approximately $1.0 million to our postretirement medical plan in 2004.

NRG Energy 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

Nine Months Ended

September 30, 2004

September 30, 2003

September 30, 2004

September 30, 2003

(In thousands)

Service cost benefits earned

2,577

—

8,477

—

Interest cost on benefit obligation

691

—

2,167

—

Amortization of prior service cost

—

Expected return on plan assets

(22

)

—

(22

)

—

Recognized actuarial (gain)/loss

—

Net periodic benefit cost

3,246

—

10,622

—


	Other Benefits
	Reorganized NRG		Predecessor Company			Reorganized NRG		Predecessor Company
	Three Months Ended		Three Months Ended			Nine Months Ended		Nine Months Ended
	September 30, 2004		September 30, 2003			September 30, 2004		September 30, 2003
	(In thousands)
Service cost benefits earned	$	372	$	334		$	1,302	$	1,002
Interest cost on benefit obligation		671		525			1,931		1,575
Amortization of prior service cost		—		(6	)		—		(18	)
Expected return on plan assets		—		—			—		—
Recognized actuarial (gain)/loss		—		48			—		144

Net periodic benefit cost	$	1,043	$	901		$	3,233	$	2,703

2003 Medicare Legislation

In May 2004, the Financial Accounting Standards Board, FASB, issued FASB Staff Position (FSP) No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003” (FSP 106-2). FSP 106-2 provides guidance on accounting for the effects of the new Medicare Prescription Drug, Improvement, and Modernization Act of 2003 by employers whose prescription drug benefits are actuarially equivalent to the drug benefit under Medicare Part D. FSP 106-2 is effective as of the first interim period beginning after June 15, 2004. NRG Energy adopted FSP 106-2 in the third quarter of 2004 on a retroactive basis. Adoption of FSP 106-2 will reduce the annual non-cash postretirement health expense by approximately $0.2 million and reduce the accumulated postretirement benefit obligation by $2.2 million. The change in accumulated postretirement benefit obligation has been reflected as an actuarial gain and will be amortized in future periods.

Note 21— 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

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., 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, the procurement of fuel and transportation services and the marketing of energy, capacity and related products in the United States and internationally. The Company has a diverse portfolio of electric generation facilities in terms of geography, fuel type and dispatch levels. NRG Energy seeks to maximize operating income through the effective procurement and trading of fuel supplies and transportation related services, and the marketing and trading of energy, capacity and ancillary services into spot, intermediate and long-term markets.

Our two principal objectives are: 1.) To maximize the operating performance of our entire portfolio and, 2.) To protect and enhance the market value of our physical and contractual assets through the execution of asset focused risk management, marketing and trading strategies within well-defined risk and liquidity guidelines. We will develop the assets in our core regions into integrated businesses well suited to serving the requirements of the load-serving entities in our core markets. 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, greater merit order diversity, enhanced portfolio effect or for alternative use, among other reasons. Our business also may involve acquisitions intended to complement the asset portfolios in our core regions, and from time to time we may also consider and undertake other merger and acquisition transactions that are consistent with our “core region” strategy.

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.

Assets Held for Sale. We have reclassified the assets and liabilities of Kendall to the held for sale category on the accompanying balance sheet as of September 30, 2004. Given our right to reacquire a 40% interest in the project, the transaction is being treated as a partial sale for accounting purposes.

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 September 30, 2004 include primarily the McClain project. For the three and nine months ended September 30, 2004, discontinued results of operations include McClain, PERC, Cobee, Hsin Yu, LSP Energy (Batesville) and several NEO Corporation projects and prior periods presented have been restated accordingly.

New Management. On October 21, 2003, we announced the appointment of David Crane as our 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 most other senior and middle management positions over the last 12 months. Our board of directors is currently comprised of Mr. Crane and ten independent individuals, three of whom have been designated by MatlinPatterson, a significant holder of NRG Energy common stock. On August 4, 2004, we held our 2004 Annual Meeting of Stockholders in which the stockholders of NRG Energy voted on four items, including the election of Class I directors. For more information, see Item 4. Submission of Matters to a Vote of Security Holders.

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, and on August 4, 2004 our stockholders ratified the appointment. For more information, see Item 4. Submission of Matters to a Vote of Security Holders.

Fresh-Start Reporting. 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 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 September 30, 2004 and 2003

Net Income/(Loss)

Reorganized NRG

For the three months ended September 30, 2004, we recorded net income of $54.2 million, or $0.54 per diluted weighted average share of common stock. Although the third quarter is typically the strongest quarter for earnings, the weather patterns in our important Northeast region, as measured by population weighted cooling degree-days, were below normal in the MidAtlantic states by 7.2% and below normal in the New England states by 3.4%. The lack of any significant heat event in the Northeast region tended to restrain power prices and earnings ability of our northeast merchant fleet. In the South Central (Louisiana) region, population weighted cooling degree-days were 1.0% above normal. In California, population weighted cooling degree-days were 6.8% above normal which favorably impacted our earnings from West Coast Power, our 50% joint venture with generating assets in California. Our results were positively impacted by $53.4 million in equity earnings of unconsolidated affiliates including $17.2 million from our interest in West Coast Power which benefited from warmer than normal temperatures during the third quarter. Our results were unfavorably impacted by impairment charges of $24.5 million related to the Kendall generating plant and $15.0 million related to the write-down of the Meriden turbine. Our results were also unfavorably impacted by write downs and losses on sales of equity investments of $13.5 million.

Predecessor Company

For the three months ended September 30, 2003, we recorded a net loss of $284.8 million. Our results were unfavorably impacted by $396.0 million of legal settlement charges recorded in connection with the resolution of the FirstEnergy Arbitration Claim, $20.7 million of reorganization expenses and $6.3 million of restructuring and impairment charges. During the third quarter of 2003 we cancelled our plans to re-establish fuel oil capacity at our Arthur Kill plant, which resulted in a charge of approximately $9.0 million to write-off assets under development. Offsetting this charge was a net gain of approximately $3.1 million relating to the sale of the Langage project. Our results were favorably impacted by a gain on the sale of equity method investments of $12.3 million resulting from the sale of our 50% interest in Mustang Station. Our results were 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 $606.7 million for the three months ended September 30, 2004, included $342.5 million of energy revenues, $174.4 million of capacity revenues, $46.4 million of alternative energy revenues, $4.7 million of O&M fees and $38.7 million of other revenues, which include financial and physical gas sales and non-cash contract amortization resulting from Fresh Start. Revenues were driven primarily by our North American operations, particularly our Northeast power generation

facilities, and to a lesser extent our South Central operations. As indicated above, mild weather limited production from our intermediate and peaking plants in the Northeast and as such, energy revenues were less than expected for the quarter. 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 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 and energy payments while improved generation performance provided for increased merchant energy sales, resulting in higher revenues than expected. Of the total dollar value of capacity revenues earned in the quarter, $47.7 million or 27.4%, were from our New York City assets. The third quarter includes three out of the six months of the summer capability period where capacity prices in New York City are at their highest level. Another 26.9% of capacity revenues this quarter were from our South Central assets. These capacity payments are typically steady quarter to quarter, and are relatively unaffected by seasonal shifts. Strong pool prices related to our Australian operations helped to offset the delayed provisional acceptance related to the final stage of the Playford Station refurbishments, originally expected to be on-line in August of 2004. Our revenues during this period include charges of $6.3 million of non-cash amortization of the fair values of various executory contracts recorded on our balance sheet upon our adoption of the Fresh Start provisions of SOP 90-7 in December 2003.

Predecessor Company

Revenues from majority-owned operations of $570.7 million for the three months ended September 30, 2003, included $317.8 million of energy revenues, $153.6 million of capacity revenues, $7.0 million of alternative energy revenues, $3.3 million of O&M fees and $89.0 million of other revenues, which include financial and physical gas sales.

Revenues from majority-owned operations during the three months ended September 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 September 30, 2004 was $381.0 million or 62.8% of revenues from majority-owned operations. Cost of majority-owned operations consists of the cost of energy (primarily fuel costs), labor, operating and maintenance costs and non-income based taxes. Of the total cost, $214.2 million is for fuel related costs including $130.5 million for coal, $61.6 million for gas and $22.1 million for oil. Generation from wholly owned North American power plants was 6.7 million megawatt hours in the third quarter of this year, up from both previous quarters. However, our intermediate and peaking facilities, which are fueled by more expensive fuel oil and natural gas and have less favorable heat conversion efficiencies than the newer generation of turbines, were not frequently called upon to generate power over the course of the quarter due to their unfavorable position in the regional dispatch curves. Included in the cost of majority-owned operations is a $10.9 million property tax credit associated with an enterprise zone program. Also included in our operating expenses is $4.6 million of amortization of the value of SO2 allowances recorded on our balance sheet resulting from Fresh Start.

Predecessor Company

Our cost of majority-owned operations related to continuing operations for the three months ended September 30, 2003 was $384.4 million or 67.4% of revenues from majority-owned operations. 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 September 30, 2004 was $51.4 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.

Predecessor Company

Our depreciation and amortization expense related to continuing operations for the three months ended September 30, 2003 was $56.5 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 September 30, 2004 were $54.3 million or 9.0% of operating revenue. These costs are primarily comprised of corporate labor, insurance and external professional support, such as legal, accounting and audit fees. General, administrative and development costs have been adversely impacted by increased costs associated with the Sarbanes Oxley implementation, engineering costs at our Arthur Kill power plant and higher labor costs associated with an increase in corporate headquarters staff in preparation for our headquarters relocation. The third quarter was also negatively impacted by a $4.5 million bad debt allowance for a note receivable held by a third party.

Predecessor Company

Our general, administrative and development costs related to continuing operations for the three months ended September 30, 2003 were $34.4 million or 6.0% of operating revenue. General, administrative and development costs were directly impacted by our efforts to streamline the operations through work force reduction efforts, closure of certain international offices and lower legal costs charged herein.

Legal Settlement Charges

During the third quarter of 2003, we recorded $396.0 million in connection with the resolution of an arbitration claim asserted by FirstEnergy Corp. As a result of this resolution, FirstEnergy retained ownership of the Lake Plant Assets and received an allowed general unsecured claim of $396.0 million under NRG Energy’s Plan of Reorganization.

Corporate Relocation Charges

through first quarter of 2005 with cash payments being made through fourth quarter of 2006. 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 $41.6 million, inclusive of the relocation charges mentioned above. All other costs and expenses relating to the corporate relocation, except for approximately $3.7 million of related capital expenditures, will be expensed as incurred and included in general, administrative and development expenses. Cash expenditures for 2004, including capital expenditures, are expected to be approximately $32 million.

Reorganization Items and Restructuring and Impairment Charges

Reorganized NRG

During the three months ended September 30, 2004, we recorded a net credit of $5.2 million related to reorganization items. These items relate primarily to the favorable settlement of obligations recorded under Fresh Start.

During the three months ended September 30, 2004, we reviewed the recoverability of our long-lived assets in accordance with SFAS No. 144. As a result of this review, we recorded $40.5 million of asset impairments related primarily to the impairment to the realizable values of Kendall Energy and the Meriden turbine (see Note 7).

Predecessor Company

During the three months ended September 30, 2003, we incurred total reorganization expenses of $20.7 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 three months ended September 30, 2003, we incurred total restructuring charges of $0.3 million. These costs consist of employee separation costs and advisor fees.

During the three months ended September 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 $6.0 million of asset impairments. During the third quarter of 2003, we cancelled our plans to re-establish fuel oil capacity at our Arthur Kill plant which resulted in a charge of approximately $9.0 million to write-off assets under development. Offsetting this charge was a net gain of approximately $3.1 million relating to the sale of the Langage project.

Other Income (Expense)

Reorganized NRG

During the three months ended September 30, 2004, we recorded other expense of $21.4 million, which consisted primarily of $66.9 million of interest expense and $13.5 million of write downs and losses on sales of equity method investments, offset by $0.1 million of minority interest in losses of consolidated subsidiaries, $53.4 million of equity in earnings of unconsolidated affiliates (including $17.2 million from our investment in West Coast Power LLC) and $5.5 million of other income, net.

Predecessor Company

During the three months ended September 30, 2003, we recorded other income of $48.5 million. Other income consisted primarily of $63.3 million of equity in earnings of unconsolidated affiliates (including $27.7 million from our investment in West Coast Power LLC), $12.3 million of gains on sales of equity method investments and $7.3 million in other income, net offset by $34.4 million of interest expense.

Equity in Earnings of Unconsolidated Affiliates

Reorganized NRG

During the three months ended September 30, 2004, we recorded $53.4 million of equity earnings from our investments in unconsolidated affiliates. Our investment in West Coast Power comprised $17.2 million of this amount with our investment in Mibrag and Gladstone comprising $3.4 million and $2.1 million, respectively. Our investment in West Coast Power generated favorable results due to the pricing under the California Department of Water Resources contract. 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.

Additionally, NRG Energy recorded a $4.2 million favorable adjustment for its James River partnership. NRG Energy’s equity earnings were also favorably impacted by $13.9 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.

Predecessor Company

During the three months ended September 30, 2003, we recorded $63.3 million of equity earnings from our investments in unconsolidated affiliates. $46.1 million was generated by our domestic portfolio and $17.2 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.

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 for the three months ended September 30, 2004 of $13.5 million and gain on sale of equity method investments of $12.3 million for the three months ended September 30, 2003.

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
	September 30, 2004			September 30, 2003
	(In thousands)
Commonwealth Atlantic Limited Partnership	$	(3,686	)	$	—
James River Power LLC		(6,008	)		—
NEO Corporation — 2004		(3,830	)		—
Mustang		—			12,310

Total write downs and gains/(losses) on sales of equity method investments	$	(13,524	)	$	12,310

NEO Corporation — 2004 — On September 30, 2004, we completed the sale of several NEO investments – Four Hills LLC, Minnesota Methane II LLC, NEO Montauk Genco LLC and NEO Montauk Gasco LLC to Algonquin Power of Canada. The sale also included four wholly owned NEO subsidiaries (see Note 3). We received proceeds of $6.1 million. The sale resulted in a loss of approximately $3.8 million attributable to the equity investment entities sold.

Other income, net

Reorganized NRG

During the three months ended September 30, 2004, we recorded $5.5 million of other income, net, consisting primarily of interest income earned on notes receivable and cash balances.

Predecessor Company

During the three months ended September 30, 2003, we recorded $7.3 million of other income, net consisting primarily of interest income earned on notes receivable and cash balances.

Interest expense

Reorganized NRG

Interest expense for the three months ended September 30, 2004 was $66.9 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 September 30, 2003 was $34.4 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 Energy 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.

Income Tax Expense

Reorganized NRG

Income tax expense for the three months ended September 30, 2004, was $14.3 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 September 30, 2004 is due to the earnings in foreign jurisdictions.

Predecessor Company

During the three months ended September 30, 2003, we recorded income tax expense of $5.4 million. The U.S. tax expense is due to separate company income tax liabilities. The foreign tax expense for the three months ended September 30, 2003 is due to earnings in foreign jurisdictions.

Income (Loss) From 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 September 30, 2004, we recorded income from discontinued operations, net of income taxes of $10.9 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, LSP Energy (Batesville) and four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC). All other discontinued operations were disposed of in prior periods. The $10.9 million income from discontinued operations is comprised primarily of a $11.0 million gain from the sale of Batesville and a $6.0 million gain associated with the sale of the four NEO wholly owned entities sold, offset by $6.4 million of income tax expense.

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 September 30, 2003, we recorded a loss on discontinued operations, net of income taxes of $0.3 million consisting of the results from our McClain, PERC, Cobee, Killingholme, NEO Landfill Gas, Inc., seven NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC), Timber Energy Resources, Inc., Cahua and Energia Pacasmayo, Hsin Yu and LSP Energy (Batesville) projects. The income on discontinued operations of $0.3 million was offset by a net loss on sale of discontinued operations of $0.6 million.

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

Net Income/(Loss)

Reorganized NRG

For the nine months ended September 30, 2004, we recorded net income of $167.5 million, or $1.67 per weighted average share of diluted common stock. Our results were favorably impacted by the cold weather in January in the Northeast region where population weighted heating degree-days were 18% above normal. Severe cold weather and gas supply problems resulted in extremely high gas and power prices in the Northeast with gas prices reaching $70/mmbtu in the New York City area. Facilities, which operate on oil such as our units in Nepool and our Oswego facility, realized a competitive advantage as their fuel costs were significantly better than gas fired units. This resulted in an increase in production from these facilities as they gained market share from gas facilities and higher margins as power prices were set by higher cost units. 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 Energy and Connecticut Light and Power and others, whereby we received $38.4 million in settlement proceeds in July 2004. The year to date September 30, 2004 results were also positively impacted by $117.2 million in equity earnings of unconsolidated affiliates including $45.1 million from our interest in West Coast Power which benefited from warmer than normal temperatures during the third quarter.

Predecessor Company

For the nine months ended September 30, 2003, we recorded a net loss of $905.8 million. Our results were unfavorably impacted by $396.0 million of legal settlement charges, $298.0 million of restructuring and impairment charges, $136.7 million of charges related to write downs and losses on our equity method investments and $27.0 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 $1.8 billion for the nine months ended September 30, 2004, included $1.1 billion of energy revenues, $473.6 million of capacity revenues, $146.8 million of alternative energy revenues, $15.3 million of O&M fees and $79.1 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 nine months ended September 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 in the winter and strong natural gas prices, which pushed up electricity prices in January 2004. Our wholly owned North America assets generated over 12.6 million megawatt hours during the nine months ended September 30, 2004. Our capacity revenues are largely driven by our Northeast and South Central facilities. Our South Central and New York City assets earned 29% and 26% of the total capacity revenues, respectively. 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 capacity 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. 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. During this period we also experienced a favorable impact on our revenues due to the mark- to-market on certain of our derivative contracts. Our revenues were 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 July 2004. The results for the nine months ended September 30, 2004 were positively impacted by $117.2 million in equity earnings of unconsolidated affiliates including $45.1 million from our interest in West Coast Power. Our revenues during this period include charges of $16.6 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.

Predecessor Company

Revenues from majority-owned operations of $1.5 billion for the nine months ended September 30, 2003, included $769.7 million of energy revenues, $469.8 million of capacity revenues, $113.1 million of alternative energy revenues, $10.3 million of O&M fees and $144.2 million of other revenues, which include financial and physical gas sales.

Revenues from majority-owned operations during the nine months ended September 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 nine months ended September 30, 2004 was $1.1 billion or 62.7% of revenues from majority-owned operations. Cost of majority-owned operations consists of the cost of energy (primarily fuel costs) of $755.3 million, labor of $153.6 million, operating and maintenance costs of $174.4 million and non-income based taxes of $32.7 million. Fuel related costs include coal costs of $361.4 million, natural gas costs of $161.9 million, fuel oil costs of $87.1 million, transmission expense of $28.1 million, purchased energy costs of $74.5 million, other costs of $27.5 million and non-cash SO2 emission credit amortization of $14.8 million resulting from Fresh Start accounting. Included in the cost of majority-owned operations is a $22.6 million property tax credit associated with an enterprise zone program.

Predecessor Company

Our cost of majority-owned operations related to continuing operations for the nine months ended September 30, 2003 was $1.1 billion or 75.8% of revenues from majority-owned operations. 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 nine months ended September 30, 2004 was $159.5 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 nine months ended September 30, 2003 was $179.2 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. Certain capitalized development costs were written-off in connection with the Loy Yang project resulting in increased expense. Amortization expense increased due to reducing the life of certain software costs.

General, Administrative and Development

Reorganized NRG

Our general, administrative and development costs related to continuing operations for the nine months ended September 30, 2004 were $136.4 million or 7.7% of operating revenue. These costs are primarily comprised of corporate labor, insurance and external professional support, such as legal, accounting and audit fees.

Predecessor Company

Our general, administrative and development costs related to continuing operations for the nine months ended September 30, 2003 were $122.1 million or 8.1% of operating revenue. General, administrative and development costs were directly impacted by our efforts to streamline the operations through work force reduction efforts, closure of certain international offices and lower legal costs charged herein. Partially offsetting these favorable variances was an increase to our bad debt expense.

Legal Settlement Charges

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 Princeton, New Jersey. The corporate headquarters staff will be streamlined as part of the relocation, 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 nine months ended September 30, 2004, we recorded $12.5 million for charges related to our corporate relocation activities, primarily for employee severance and termination benefits and employee related transition costs. We expect to incur $25.2 million of expenses in connection with corporate relocation charges. Relocating, recruiting and other employee-related transition costs are expected to be approximately $11.8 million and will be expensed as incurred. These costs and cash payments are expected to be incurred through first quarter of 2005. Severance and termination benefits of $8.3 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. 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 $41.6 million, inclusive of the relocation charges mentioned above. All other costs and expenses relating to the corporate relocation, except for approximately $3.7 million of related capital expenditures, will be expensed as incurred and included in general, administrative and development expenses. Cash expenditures for 2004, including capital expenditures, are expected to be approximately $32 million.

We expect to recognize a curtailment gain on our defined benefit pension plan in the fourth 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 nine months ended September 30, 2004, we recorded a net credit of $1.7 million related to reorganization items. These items relate primarily to the favorable settlement of obligations recorded under Fresh Start.

During the nine months ended September 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 $42.2 million of asset impairments related primarily to impairments at Kendall Energy and the Meriden turbine (see Note 7).

Predecessor Company

During the nine months ended September 30, 2003, we incurred total reorganization expenses of $27.0 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 nine months ended September 30, 2003, we incurred total restructuring charges of $68.5 million. These costs consist of employee separation costs and advisor fees.

During the nine months ended September 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 $229.6 million of asset impairments primarily related to our Devon, Middletown and Arthur Kill facilities resulting from adverse regulatory developments affecting these facilities.

Other Income (Expense)

Reorganized NRG

During the nine months ended September 30, 2004, we recorded other expense of $106.5 million. Other expense consisted primarily of $226.2 million of interest expense, $0.6 million of minority interest in earnings of consolidated subsidiaries and $14.1 million of write downs and losses on sales of equity method investments, offset by $117.2 million of equity in earnings of unconsolidated affiliates (including $45.1 million from our investment in West Coast Power LLC) and $17.2 million of other income, net.

Predecessor Company

During the nine months ended September 30, 2003, we recorded other expense of $265.3 million. Other expense consisted primarily of $294.5 million of interest expense, $136.7 million of write downs and losses on sales of equity method investments, offset by $10.1 million of other income, net and $155.8 million of equity in earnings of unconsolidated affiliates (including $27.3 million from our investment in West Coast Power LLC).

Equity in Earnings of Unconsolidated Affiliates

Reorganized NRG

During the nine months ended September 30, 2004, we recorded $117.2 million of equity earnings from our investments in unconsolidated affiliates. Our investment in West Coast Power comprised $45.1 million of this amount with our investment in Mibrag and Gladstone comprising $14.2 million and $8.8 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, revenues from ancillary services revenue and minimum load cost compensation power positively contributed to 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 Energy’s equity earnings were also favorably impacted by $23.0 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. Additionally, NRG Energy recorded a $4.2 million favorable adjustment for its James River partnership.

Predecessor Company

During the nine months ended September 30, 2003, we recorded $155.8 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.

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 nine months ended September 30, 2004 and 2003 of $14.1 million and $136.7 million, respectively.

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


	Reorganized			Predecessor
	NRG			Company
	Nine Months			Nine Months
	Ended			Ended
	September 30,			September 30,
	2004			2003
	(In thousands)
Commonwealth Atlantic Limited Partnership	$	(3,686	)	$	—
James River Power LLC		(6,008	)		—
NEO Corporation — 2004		(3,830	)		—
Calpine Cogeneration		735			—
Loy Yang		(1,268	)		(139,972	)
NEO Corporation — Minnesota Methane		—			(12,257	)
Kondapalli		—			519
ECKG		—			2,869
Mustang		—			12,124

Total write downs and losses on sales of equity method investments	$	(14,057	)	$	(136,717	)

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 resulting from the legal release of certain obligations. This resulted in an adjusted loss of $12.3 million for the nine months ended September 30, 2003.

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 which resulted in cash proceeds of $65.3 million and a net gain of $2.9 million.

Other Income, net

Reorganized NRG

During the nine months ended September 30, 2004, we recorded $17.2 million of other income, net, consisting primarily of interest income earned on notes receivable and cash balances.

Predecessor Company

During the nine months ended September 30, 2003, we recorded $10.1 million of 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.

Interest Expense

Reorganized NRG

Interest expense for the nine months ended September 30, 2004 was $226.2 million, consisting of interest expense on both our project and corporate level interest bearing debt. Significant amounts of our corporate level debt were forgiven upon our emergence from bankruptcy and we refinanced significant amounts of our project level debt with corporate level high yield notes and term loans in December 2003. 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 nine months ended September 30, 2003 was $294.5 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 Energy 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.

Income Tax Expense

Reorganized NRG

Income tax expense for the nine months ended September 30, 2004, was $64.9 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 tax expense for the nine months ended September 30, 2004 includes U.S. tax expense of $54.6 million and foreign tax expense of $10.3 million. The foreign tax expense for the nine months ended September 30, 2004 is due to earnings in foreign jurisdictions.

We have assessed the likelihood that a substantial portion of the deferred tax assets relating to the net operating loss carryforwards would not be realized. This assessment included consideration of positive and negative factors, including our current financial position and results of operations, projected future taxable income, including projected operating and capital gains, and available tax planning strategies. As a result of such assessment, we determined that it was more likely than not that the deferred tax assets related to our domestic net operating loss carryforwards would not be realized. As noted above, a full valuation allowance was recorded against the net deferred tax assets including net operating loss carryforwards. We also determined that it is more likely than not that a substantial portion of the net operating loss generated in 2002 and 2003 could be determined to be capital in nature. Given that capital losses are of a different character than ordinary losses the likelihood of capital losses expiring unutilized is greater than that of ordinary net operating losses.

Predecessor Company

During the nine months ended September 30, 2003, we recorded income tax expense of $42.8 million. The tax expense for the nine months ended September 30, 2003 includes U.S. tax expense of $36.1 million and foreign tax expense of $6.7 million. The U.S. tax expense 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 from a corporation to a disregarded entity for federal income tax purposes. The foreign tax expense for the nine months ended September 30, 2003 is due to earnings in foreign jurisdictions. As of December 31, 2003, a valuation allowance of $556.6 million was provided to account for potential limitations on utilization of U.S. and foreign net operating loss carryforwards and a valuation allowance of $684.5 million was provided for other deferred tax assets.

Income From 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 nine months ended September 30, 2004, we recorded income from discontinued operations, net of income taxes of $23.3 million. During this period, discontinued operations consisted of the results of our NRG McClain LLC, PERC, Cobee, Hsin Yu, LSP Energy (Batesville) and four NEO Corporation projects (NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC). All other discontinued operations were disposed of in prior periods. The $23.3 million income from discontinued operations includes a gain of $22.4 million, net of income taxes of $7.8 million, related primarily to the dispositions of Batesville and Hsin Yu.

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 nine months ended September 30, 2003, we recorded income on discontinued operations, net of income taxes of $60.4 million consisting of the results from our McClain, PERC, Cobee, Killingholme, NEO Landfill Gas, Inc., seven NEO Corporation projects (NEO Fort Smith LLC, NEO Woodville LLC, NEO Phoenix LLC, NEO Nashville LLC, NEO Hackensack LLC, NEO Prima Deshecha and NEO Tajiguas LLC), Timber Energy Resources, Inc., Cahua and Energia Pacasmayo, Hsin Yu and LSP Energy (Batesville) projects. The $60.4 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 and $23.6 million related to subsidiaries of NLGI.

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 Energy 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 18 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 November 2, 2004, we had $1.725 billion in aggregate principal amount of 8% Second Priority Notes outstanding, $441.3 million principal amount outstanding under the term loan and $98.9 million remains available under the funded letter of credit facility. As of November 2, 2004, we had not drawn down on our revolving credit facility.

In connection with our power generation business, we manage the commodity price risk associated with our supply activities and our electric generation facilities. This includes forward power sales, fuel and energy purchases and emission credits. In order to manage these risks, we enter into financial instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel and energy. We utilize a variety of instruments including forward contracts, future contracts, swaps and options. Certain of these contracts allow counterparties to require NRG to post margin. As of September 30, 2004 and November 1, 2004, we have posted $42.3 million and $99.6 million, respectively, in collateral to support these contracts.

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 September 30, 2004 and as of November 2, 2004, we had not posted any collateral.

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

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 received 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. We received $288.0 million, $328.5 million and $23.5 million from Xcel Energy on February 20, 2004, April 30, 2004 and May 28, 2004, respectively. We used the proceeds from the Xcel Energy settlement to reduce our creditor pool obligation. As of September 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, May 28, 2004 and October 29, 2004, we made payments of $163.0 million, $328.5 million, $23.5 million and $25.0 million, respectively.

As part of the NRG Energy’s 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 $78.3 million for the nine months ended September 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, including the conversion of certain coal-fired plants in New York and Delaware to combust lower sulfur coal from the Powder River Basin.

Liquidity

As of September 30, 2004 our liquidity was $1.6 billion and includes $1.3 billion of cash and restricted cash. Our liquidity also includes $250.0 million of available capacity under our revolving line of credit and $97.5 million of availability under our letter of credit facility. As of December 31, 2003 our liquidity was $1.2 billion and included $667.3 million of cash and restricted cash. Our liquidity also included $250.0 million of available capacity under our revolving line of credit and $248.3 million of availability under our letter of credit facility.

Other Liquidity Matters – NOL

As of September 30, 2004, the valuation allowance against U.S. and foreign net operating loss carryforwards was $400.5 million and the valuation allowance against other deferred tax assets was $658.2 million. As of December 31, 2003, a valuation allowance of $556.6 million was provided to account for potential limitations on utilization of U.S. and foreign net operating loss carryforwards, and a valuation allowance of $684.5 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.

Cash Flows


	Reorganized NRG			Predecessor Company
	For the Nine Months			For the Nine Months
	Ended			Ended
	September 30, 2004			September 30, 2003
	(In thousands)
Net cash provided by operating activities	$	595,421		$	121,315
Net cash (used) provided by investing activities		210,806			(160,124	)
Net cash used by financing activities		(227,633	)		(24,119	)

Net Cash Provided By Operating Activities

Reorganized NRG

For the nine months ended September 30, 2004, cash provided by operating activities was $595.4 million. This was primarily a result of net income after non-cash charges of $466.9 million and $640.0 million received in connection with the Xcel Energy settlement agreement, offset by payments made in connection with our creditor pool obligation.

Predecessor Company

For the nine months ended September 30, 2003, cash provided by operating activities was $121.3 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 a decrease in accounts payable and a decrease in accrued interest, due to our not making scheduled interest payments.

Net Cash Provided By Investing Activities

Reorganized NRG

For the nine months ended September 30, 2004, cash provided by investment activities was $210.8 million. This was primarily due to proceeds from the sales of discontinued operations and equity method investments offset by ongoing capital improvement projects at our South Central and Northeast facilities.

Predecessor Company

For the nine months ended September 30, 2003, cash used by investing activities was $160.1 million. This was primarily a result of an increase in restricted cash due to providing deposits for certain operating expenses and collateral deposits and capital expenditures made offset by cash proceeds received upon the sale of investments.

Net Cash Used By Financing Activities

Reorganized NRG

For the nine months ended September 30, 2004, cash used by financing activities was $227.6 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 nine months ended September 30, 2003, cash used by financing activities was $24.1 million, resulting primarily from principal payments on short and long-term debt and an increase in deferred debt issuance costs offset by proceeds from the issuance of long-term debt.

Off-Balance Sheet Arrangements

As of September 30, 2004, we have not entered into any 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 September 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 unconsolidated 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.

Rail Car Agreement — On August 23, 2004, NRG Power Marketing Inc. entered into an agreement with a vendor for the construction of 1,540 aluminum rail cars to be put into service for the transportation of Powder River Basin coal from Wyoming to NRG Energy’s coal burning generating plants. NRG Energy has the right to either purchase the rail cars outright for a value of $85.9 million or lease them from this vendor for lease term options ranging from 3 to 10 years. Delivery of the rail cars will commence in January 2005. At this time NRG Energy plans to lease rather than purchase these rail cars and is exploring lease terms with rail car leasing companies. It is anticipated that any lease arrangement would be accounted for as an operating lease.

The following is a summarized table of contractual obligations:


	Payments Due by Period as of September 30, 2004
Contractual Cash									After
Obligations	Total		Short Term		2-3 Years		4-5 Years		5 Years
	(In thousands)
Long-term debt	$	3,084,762	$	36,706	$	100,922	$	91,847	$	2,855,287
Capital lease obligations		526,574		63,399		122,474		60,155		280,546
Operating leases		47,522		9,224		15,524		7,840		14,934
Coal purchase agreements		162,790		97,870		61,800		3,120		—

Total contractual cash obligations	$	3,821,648	$	207,199	$	300,720	$	162,962	$	3,150,767


	Amount of Commitment Expiration per Period as of September 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		168,638		168,638		—		—		—
Cash collateral calls		—		—		—		—		—
Guarantees of subsidiaries		526,336		750		20,518		12,500		492,568
Guarantees of NRG PMI obligations		42,100		10,000		5,000		—		27,100
Guarantees of NE Genco obligations		12,339		—		—		—		12,339

Total commercial commitments	$	749,413	$	179,388	$	25,518	$	12,500	$	532,007

Derivative Instruments

In connection with our power generation business, we manage the commodity price risk associated with our supply activities and our electric generation facilities. This includes forward power sales, fuel and energy purchases and emission credits. In order to manage these risks, we enter into financial instruments to hedge the variability in future cash flows from forecasted sales of electricity and purchases of fuel and energy. We utilize a variety of instruments including forward contracts, future contracts, swaps and options. Certain of these contracts allow counterparties to require NRG to post margin. As of September 30, 2004 and November 1, 2004 we have posted $42.3 million and $99.6 million, respectively, in collateral to support these contracts.

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 September 30, 2004 and as of November 2, 2004, we had posted no collateral in support of the swaps. During the three months ended September 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.

Changes in Accounting Standards – 2003 Medicare Legislation

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks associated with commodity prices, credit exposure, interest rates and foreign currency exchange rates. It is our practice to use derivatives to manage risk consistent with our business plans and prudent practices. We have formed the Financial Risk Management Committee (FRMC), consisting of senior officers, to oversee company wide energy risk management activities and monitor the results of trading activities to ensure compliance with the Company’s energy management policies, as aided by the Risk Management Group. 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 September 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 September 30, 2004, we had various interest rate swap agreements with notional amounts totaling approximately $1.7 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 swaps had been discontinued on September 30, 2004, we would have owed the counterparties approximately $63.7 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 September 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 $7.9 million.

At September 30, 2004, the fair value of our fixed-rate debt was $1.9 billion, compared with the carrying amount of $1.9 billion. We estimate that a 1% decrease in market interest rates would have increased the fair value of our fixed-rate debt to $2.0 billion, or an increase of $100.6 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 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 including those accounted for as a hedge under SFAS No. 133 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.

We use a diversified VAR model to calculate the 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. The key assumptions for our model include (1) a lognormal distribution of price returns (2) one day holding period (3) a 95% confidence interval, (4) a rolling 24 month forward looking period and (5) 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 VAR model is as follows:


	(In millions)
Quarter ending September 30, 2004 (Diversified)	$	40.8
Average		39.5
High		44.7
Low		34.2
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.

Significant Customers

For the quarter ended September 30, 2004, we derived approximately 39.3% of our total revenues from majority-owned operations from two customers: NYISO accounted for 28.6% and ISO-New England accounted for 10.7%. For the nine months ended September 30, 2004, we derived approximately 38.6% of our total revenues from majority-owned operations from two customers: NYISO accounted for 29.0% and ISO-New England accounted for 9.6%. We account for revenues attributable to the NYISO and ISO-New England as part of our Wholesale Power Generation – Northeast segment. NYISO and ISO-New England are FERC-regulated independent system operators that manage transmission assets collectively under their control to provide non-discriminatory access to their respective transmission grids. The NYISO exercises operational control over most of New York State’s transmission facilities. We anticipate that NYISO will continue to be a significant customer given the scale of our asset base in the NYISO control area.

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, our principal executive and principal financial officers concluded that our disclosure controls and procedures were effective as of that time.

Management noted, however, that as previously announced, we are in the process of moving our corporate headquarters from Minneapolis, Minnesota to Princeton, 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 Chief Financial Officer, effective March 29, 2004, and James Ingoldsby as our Controller, effective May 3, 2004. In addition, we hired a Director of Internal Audit, a Chief Risk Officer and have hired approximately eighty percent of the Princeton accounting and finance staff. To address transition issues, we have implemented a transition plan and established a staff retention bonus program. We 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. There can be no assurance, however, that we will be successful in that regard.

In preparation for NRG Energy’s December 31, 2004 audit of internal controls over financial reporting, management identified deficiencies in controls related to its information technology systems. Specifically, the deficiencies identified involved systems security, segregation of duties, change management, documentation and data recovery processes. We performed remediation of a substantial number of these deficiencies during the third quarter. Remediation, documentation and testing activities were underway at September 30, 2004 and have continued into the fourth quarter. We intend to complete these activities prior to December 31, 2004. Management has not detected any errors or irregularities in its financial records and systems as a result of these deficiencies.

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 flows of NRG Energy as of, and for the periods presented in this report.

Other than as described 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 September 30, 2004, see Note 18 “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

None.

Item 4. Submission of Matters to a Vote of Security Holders

The stockholders of NRG Energy, Inc. voted on four items at the Annual Meeting of Stockholders held on August 4, 2004:

1. The election of Class I Directors to a three-year term.

2. The proposal to approve NRG Energy’s Long-Term Incentive Plan.

3. The proposal to approve NRG Energy’s Annual Incentive Plan for Designated Corporate Officers.

4. The proposal to ratify the appointment of KPMG LLP as NRG Energy’s independent registered public accounting firm.

There were 100,006,798 shares of Common stock entitled to vote at the meeting, and a total of 81,071,563 of NRG Energy’s shares (81.07%) were represented at the meeting.

The four individuals named below were elected to serve a three-year term as Class I Directors expiring at the annual meeting of stockholders in 2007:


Nominee	Votes For		Votes Withheld
Ramon Betolaza		80,806,570		264,993
David Crane		81,046,223		25,340
Stephen L. Cropper		80,794,982		276,581
Thomas H. Weidemeyer		81,050,440		21,123

The proposal to approve NRG Energy’s Long-Term Incentive Plan was approved with 48,812,612 shares voting for, 10,329,190 shares voting against, 78,069 shares abstaining and 21,851,692 broker non-votes.

The proposal to approve NRG Energy’s Annual Incentive Plan for Designated Corporate Officers was approved with 58,854,477 shares voting for, 285,570 shares voting against, 79,824 shares abstaining and 21,851,692 broker non-votes.

The proposal to ratify the appointment of KPMG LLP as NRG Energy’s independent registered public accounting firm was ratified with 80,736,682 shares voting for, 266,498 shares voting against and 68,383 shares abstaining.

Item 5. Other Information

None.

Item 6. Exhibits

(a) Exhibits

10.1 Form of NRG Energy, Inc. Long-Term Incentive Plan Non-Qualified Stock Option Agreement.

10.2 Form of NRG Energy, Inc. Long-Term Incentive Plan Restricted Stock Unit Agreement.

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.

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,” “may,” “will,” “should” 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 our 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 power generation operations such as fuel and electricity price volatility, 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 and the possibility that we may not have adequate insurance to cover losses as a result of such hazards;

• Our potential inability to enter into contracts to sell power and procure fuel on terms and prices acceptable to us;

• The liquidity and competitiveness of wholesale markets for energy commodities;

• 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;

• Our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward; and

• Significant operating and financial restrictions placed on us contained in the indenture governing our note offerings and our existing credit facility, as well as in debt and other agreements of certain of our subsidiaries and project affiliates generally.

Forward-looking statements speak only as of the date they were made, and 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.


	Page No.
Part I — FINANCIAL INFORMATION
Item 1 Consolidated Financial Statements and Notes
Consolidated Statements of Operations		3
Consolidated Balance Sheets		4
Consolidated Statements of Stockholders’ Equity/(Deficit) and Comprehensive Income/(Loss)		6
Consolidated Statements of Cash Flows		8
Notes to Consolidated Financial Statements		9
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
Item 3 Quantitative and Qualitative Disclosures About Market Risk		56
Item 4 Controls and Procedures		58
Part II — OTHER INFORMATION
Item 1 Legal Proceedings		59
Item 3 Defaults Upon Senior Securities		59
Item 4 Submission of Matters to a Vote of Security Holders		59
Item 5 Other Information		59
Item 6 Exhibits and Reports on Form 8-K		59
Cautionary Statement Regarding Forward Looking Information		60
SIGNATURES		61
Exhibit Index		62
Form of Long-Term Incentive Plan Non-Qualified Stock Option Agreement
Form of Long-Term Incentive Plan Restricted Stock Unit Agreement
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 Pursuant to Section 906


	September 30,			December 31,
	2004			2003
	(In thousands)
ASSETS
Current Assets
Cash and cash equivalents	$	1,104,783		$	551,223
Restricted cash		148,919			116,067
Accounts receivable — trade, less allowance for doubtful accounts of $908 and $0		242,245			201,921
Xcel Energy settlement receivable		—			640,000
Current portion of notes receivable — affiliates		—			200
Current portion of notes receivable		121,599			65,141
Taxes receivable		30,931			—
Inventory		214,980			194,926
Derivative instruments valuation		5,516			772
Prepayments and other current assets		196,078			222,138
Current deferred income taxes		989			1,850
Current assets — held for sale		43,851			—
Current assets — discontinued operations		3,042			119,601

Total current assets		2,112,933			2,113,839

Property, Plant and Equipment
In service		3,439,499			3,885,465
Under construction		68,135			139,171

Total property, plant and equipment		3,507,634			4,024,636
Less accumulated depreciation		(156,643	)		(11,800	)

Net property, plant and equipment		3,350,991			4,012,836

Other Assets
Equity investments in affiliates		689,974			737,998
Notes receivable, less current portion — affiliates		118,200			130,152
Notes receivable, less current portion		612,443			691,444
Intangible assets, net of accumulated amortization of $45,593 and $5,212		326,030			432,361
Debt issuance costs, net of accumulated amortization of $7,372 and $454		60,658			74,337
Derivative instruments valuation		48,928			59,907
Funded letter of credit		250,000			250,000
Other assets		95,441			118,940
Non-current assets — held for sale		519,986			—
Non-current assets — discontinued operations		—			623,173

Total other assets		2,721,660			3,118,312

Total Assets	$	8,185,584		$	9,244,987


	Common				Additional					Accumulated Other			Total
					Paid-in		Retained Earnings/			Comprehensive			Stockholders’
	Stock		Shares		Capital		(Accumulated Deficit)			Income/(Loss)			Equity/(Deficit)
	(In thousands)
Balances at June 30, 2003 (Predecessor Company)	$	—		—	$	2,227,692	$	(3,449,966	)	$	(56,072	)	$	(1,278,346	)
Net loss								(284,794	)					(284,794	)
Foreign currency translation adjustments and other											(3,133	)		(3,133	)
Deferred unrealized gain on derivatives, net											35,056			35,056

Comprehensive loss for the three months ended September 30, 2003														(252,871	)

Balances at September 30, 2003 (Predecessor Company)	$	—		—	$	2,227,692	$	(3,734,760	)	$	(24,149	)	$	(1,531,217	)

Balances at June 30, 2004 (Reorganized NRG)	$	1,000		100,007	$	2,410,751	$	124,284		$	43		$	2,536,078
Net income								54,221						54,221
Foreign currency translation adjustments and other											22,434			22,434
Deferred unrealized loss on derivatives, net											(18,793	)		(18,793	)

Comprehensive income for the three months ended September 30, 2004														57,862
Equity based compensation				1		3,211								3,211

Balances at September 30, 2004 (Reorganized NRG)	$	1,000		100,008	$	2,413,962	$	178,505		$	3,684		$	2,597,151


	Common				Additional					Accumulated Other			Total
					Paid-in		Retained Earnings/			Comprehensive			Stockholders’
	Stock		Shares		Capital		(Accumulated Deficit)			Income/(Loss)			Equity/(Deficit)
	(In thousands)
Balances at December 31, 2002 (Predecessor Company)	$	—		—	$	2,227,692	$	(2,828,933	)	$	(94,958	)	$	(696,199	)
Net loss								(905,827	)					(905,827	)
Foreign currency translation adjustments and other											87,734			87,734
Deferred unrealized loss on derivatives, net											(16,925	)		(16,925	)

Comprehensive loss for the nine months ended September 30, 2003														(835,018	)

Balances at September 30, 2003 (Predecessor Company)	$	—		—	$	2,227,692	$	(3,734,760	)	$	(24,149	)	$	(1,531,217	)

Balances at December 31, 2003 (Reorganized NRG)	$	1,000		100,000	$	2,403,429	$	11,025		$	21,802		$	2,437,256
Net income								167,480						167,480
Foreign currency translation adjustments and other											(13,499	)		(13,499	)
Deferred unrealized loss on derivatives, net											(4,619	)		(4,619	)

Comprehensive income for the nine months ended September 30, 2004														149,362
Equity based compensation				8		10,533								10,533

Balances at September 30, 2004 (Reorganized NRG)	$	1,000		100,008	$	2,413,962	$	178,505		$	3,684		$	2,597,151


	September 30, 2004		December 31, 2003
	(In thousands)
Fuel oil	$	103,411	$	75,272
Coal		53,678		59,555
Natural gas		695		856
Other fuels		86		75
Spare parts		52,378		54,522
Emission credits		4,263		4,478
Other		469		168

Total inventory	$	214,980	$	194,926


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

	1.		The election of Class I Directors to a three-year term.

	2.		The proposal to approve NRG Energy’s Long-Term Incentive Plan.

	3.		The proposal to approve NRG Energy’s Annual Incentive Plan for Designated Corporate Officers.

	4.		The proposal to ratify the appointment of KPMG LLP as NRG Energy’s independent registered public accounting firm.

			NRG ENERGY, INC. (Registrant)

			/s/ DAVID CRANE David Crane, Chief Executive Officer

			/s/ ROBERT FLEXON Robert Flexon, Chief Financial Officer (Principal Financial Officer)

			/s/ JAMES INGOLDSBY James Ingoldsby, Controller (Principal Accounting Officer)