UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

þ		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, 2005		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.)

211 Carnegie Center Princeton, New Jersey (Address of principal executive offices)		08540 (Zip Code)

(609) 524-4500
(Registrant’s telephone number, including area code)

     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.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

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

     As of November 3, 2005, there were 80,701,198 shares of common stock outstanding.

 

 

TABLE OF CONTENTS

Index

		Page No.
Cautionary Statement Regarding Forward Looking Information			3
Part I — FINANCIAL INFORMATION
Item 1 Condensed Consolidated Financial Statements and Notes
Condensed Consolidated Statements of Operations			4
Condensed Consolidated Balance Sheets			5
Condensed Consolidated Statements of Stockholders’ Equity			6
Condensed Consolidated Statements of Cash Flows			7
Notes to Condensed Consolidated Financial Statements			8
Item 2 Management’s Discussion and Analysis of Financial Condition and Results of Operations			41
Item 3 Quantitative and Qualitative Disclosures About Market Risk			68
Item 4 Controls and Procedures			71
Part II — OTHER INFORMATION			71
Item 1. Legal Proceedings			71
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds			71
Item 3. Defaults Upon Senior Securities			71
Item 4. Submission of Matters to a Vote of Security Holders			72
Item 5. Other Information			72
Item 6. Exhibits			72
SIGNATURES			73
Exhibit Index			74
EX-31.1: CERTIFICATION
EX-31.2: CERTIFICATION
EX-31.3: CERTIFICATION
EX-32: CERTIFICATION

Cautionary Statement Regarding Forward Looking Information

     This Quarterly Report on Form 10-Q includes forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Securities Exchange Act. The words “believes,” “projects,” “anticipates,” “plans,” “expects,” “intends,” “estimates” and similar expressions are intended to identify forward-looking statements. These forward-looking statements involve known and unknown risks, uncertainties and other factors which may cause our actual results, performance and achievements, or industry results, to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statement. These factors, risks and uncertainties include the factors described under Risks Related to NRG Energy, Inc. in Item 1 of the Company’s Annual Report on Form 10-K and the following:

	•		Risks and uncertainties related to the capital markets generally, including increases in interest rates and the availability of financing for our proposed acquisition of Texas Genco LLC as described in this Quarterly Report under the caption Note 1, General — Recent Developments — Texas Genco Acquisition, to Condensed Consolidated Financial Statements as well as our operating requirements;
	•		Our indebtedness and the additional indebtedness that we will incur in connection with the proposed acquisition;
	•		The ability to successfully complete the acquisition of Texas Genco LLC, regulatory or other limitations that may be imposed as a result of the acquisition, and the success of the business following the acquisition;
	•		General economic conditions, changes in the wholesale power markets and fluctuations in the cost of fuel or other raw materials;
	•		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 possible changes of market rules, market structures and design, rates, tariffs, environmental laws and regulations and regulatory compliance requirements;
	•		Price mitigation strategies and other market structures or designs employed by independent system operators, or ISOs, or regional transmission organizations, or RTOs, that result in a failure to adequately compensate our generation units for all of their costs;
	•		Our ability to realize our significant deferred tax assets, including loss carry forwards;
	•		The effectiveness of our risk management policies and procedures and the ability of our counterparties to satisfy their financial commitments;
	•		Counterparties’ collateral demands and other factors affecting our liquidity position and financial condition;
	•		Our ability to operate our businesses efficiently, manage capital expenditures and costs (including general and administrative expenses) tightly and generate earnings and cash flow from our asset-based businesses in relation to our debt and other obligations;
	•		Significant operating and financial restrictions placed on us contained in the indenture governing our 8% second priority senior secured notes due 2013, our amended and restated 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 on Form 10-Q should not be construed as exhaustive.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)

		Three Months								Nine Months
		Ended								Ended
		September 30,				September 30,				September 30,				September 30,
		2005				2004				2005				2004
		(In thousands, except for per share amounts)
Operating Revenues
Revenues from majority-owned operations		$	765,316			$	604,632			$	1,942,828			$	1,770,669
Operating Costs and Expenses
Cost of majority-owned operations			668,373				379,855				1,555,737				1,112,479
Depreciation and amortization			48,802				51,060				144,317				158,603
General, administrative and development			47,185				54,031				149,641				135,673
Other charges
Corporate relocation charges			1,740				5,713				5,651				12,474
Reorganization items			—				(5,245	)			—				(1,656	)
Impairment charges			6,000				40,507				6,223				42,183
Total operating costs and expenses			772,100				525,921				1,861,569				1,459,756
Operating Income/(Loss)			(6,784	)			78,711				81,259				310,913
Other Income (Expense)
Minority interest in earnings of consolidated subsidiaries			(13	)			(18	)			(36	)			(18	)
Equity in earnings of unconsolidated affiliates			29,077				53,373				82,501				117,187
Write downs and gains/(losses) on sales of equity method investments			4,333				(13,524	)			15,894				(14,057	)
Other income, net			9,956				5,478				43,208				17,145
Refinancing expense			(19,012	)			—				(44,036	)			(30,417	)
Interest expense			(45,791	)			(66,110	)			(150,598	)			(193,463	)
Total other expense			(21,450	)			(20,801	)			(53,067	)			(103,623	)
Income/(Loss) From Continuing Operations Before Income Taxes			(28,234	)			57,910				28,192				207,290
Income Tax Expense			8,511				14,559				21,201				65,136
Income/(Loss) From Continuing Operations			(36,745	)			43,351				6,991				142,154
Income from discontinued operations, net of income taxes			9,864				10,870				12,612				25,326
Net Income/(Loss)			(26,881	)			54,221				19,603				167,480
Preference stock dividends			4,200				—				12,272				—
Income/(Loss) Available for Common Stockholders		$	(31,081	)		$	54,221			$	7,331			$	167,480
Weighted Average Number of Common Shares Outstanding — Basic			83,529				100,101				85,860				100,066
Income/(Loss) From Continuing Operations per Weighted Average Common Share — Basic		$	(0.51	)		$	0.43			$	(0.08	)		$	1.42
Income From Discontinued Operations per Weighted Average Common Share — Basic			0.12				0.11				0.15				0.25
Income/(Loss) Available for Common Stockholders per Weighted Average Common Share — Basic		$	(0.39	)		$	0.54			$	0.07			$	1.67
Weighted Average Number of Common Shares Outstanding — Diluted			83,529				100,616				85,860				100,328
Income/(Loss) From Continuing Operations per Weighted Average Common Share — Diluted		$	(0.51	)		$	0.43			$	(0.08	)		$	1.42
Income From Discontinued Operations per Weighted Average Common Share — Diluted			0.12				0.11				0.15				0.25
Income/(Loss) Available for Common Stockholders per Weighted Average Common Share — Diluted		$	(0.39	)		$	0.54			$	0.07			$	1.67

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

		September 30,				December 31,
		2005				2004
		(unaudited)
		(In thousands)
ASSETS
Current Assets
Cash and cash equivalents		$	504,336			$	1,103,678
Restricted cash			91,508				109,633
Accounts receivable, less allowance for doubtful accounts of $3,280 and $6,591			308,839				269,611
Current portion of notes receivable			24,934				85,447
Income taxes receivable			31,237				37,484
Inventory			203,547				248,010
Derivative instruments valuation			451,545				79,759
Prepayments and other current assets			129,289				135,520
Collateral on deposit in support of energy risk management activities			631,436				33,325
Deferred income taxes			44,832				—
Current assets — discontinued operations			—				15,821
Total current assets			2,421,503				2,118,288
Property, plant and equipment, net of accumulated depreciation of $346,886 and $205,928			3,226,714				3,329,000
Other Assets
Equity investments in affiliates			651,412				734,950
Notes receivable, less current portion, less reserve for uncollectible notes of $0 and $8,196			712,020				804,450
Intangible assets, net			268,897				294,350
Derivative instruments valuation			31,973				41,787
Funded letter of credit			350,000				350,000
Other non-current assets			132,848				111,574
Non-current assets — discontinued operations			—				45,884
Total other assets			2,147,150				2,382,995
Total Assets		$	7,795,367			$	7,830,283
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases		$	176,024			$	511,258
Accounts payable			152,968				171,722
Derivative instruments valuation			973,143				16,772
Deferred income taxes			—				334
Other bankruptcy settlement			175,945				175,576
Accrued expenses and other current liabilities			389,396				209,367
Current liabilities — discontinued operations			—				2,912
Total current liabilities			1,867,476				1,087,941
Other Liabilities
Long-term debt and capital leases			2,866,374				3,212,596
Deferred income taxes			103,199				134,580
Derivative instruments valuation			198,554				148,445
Out-of-market contracts			302,639				318,664
Other non-current liabilities			190,897				187,438
Non-current liabilities — discontinued operations			—				47,759
Total non-current liabilities			3,661,663				4,049,482
Total Liabilities			5,529,139				5,137,423
Minority Interest			869				696
3.625% Convertible Perpetual Preferred Stock; $.01 par value; 10,000,000 shares authorized, 250,000 shares issued and outstanding (at liquidation value, net of issuance costs)			246,191				—
Commitments and Contingencies
Stockholders’ Equity
4% Convertible Perpetual Preferred Stock; $.01 par value; 10,000,000 shares authorized, 420,000 issued and outstanding (at liquidation value, net of issuance costs)			406,155				406,359
Common Stock; $.01 par value; 500,000,000 shares authorized; 80,701,198 and 87,041,935 outstanding			1,000				1,000
Additional paid-in capital			2,427,322				2,417,021
Retained earnings			203,973				196,642
Less treasury stock, at cost — 19,346,788 and 13,000,000 shares			(663,529	)			(405,312	)
Accumulated other comprehensive income/(loss)			(355,753	)			76,454
Total stockholders’ equity			2,019,168				2,692,164
Total Liabilities and Stockholders’ Equity		$	7,795,367			$	7,830,283

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

																														Accumulated
																		Additional												Other				Total
		Serial Preferred								Common								Paid-in				Retained				Treasury				Comprehensive				Stockholders’
(In thousands)		Stock				Shares				Stock				Shares				Capital				Earnings				Stock				Income/(loss)				Equity
Balances at June 30, 2004			—				—			$	1,000				100,007			$	2,410,751			$	124,284			$	—			$	43			$	2,536,078
Net income																							54,221												54,221
Foreign currency translation adjustments																															22,434				22,434
Deferred unrealized loss on derivatives, net																															(18,793	)			(18,793	)
Comprehensive income																																			57,862
Equity compensation			—				—				—				1				3,211				—				—				—			$	3,211
Balances at September 30, 2004			—				—			$	1,000				100,008			$	2,413,962			$	178,505			$	—			$	3,684			$	2,597,151
Balances at June 30, 2005			406,155				420				1,000				87,045				2,423,636				235,054				(405,312	)			(59,882	)			2,600,651
Net loss																							(26,881	)											(26,881	)
Foreign currency translation adjustments																															(572	)			(572	)
Deferred unrealized loss on derivatives																															(295,604	)			(295,604	)
Unrealized gain on available for sale securities by affiliate																															305				305
Comprehensive loss																																			(322,752	)
4% Preferred Stock dividend																							(4,200	)											(4,200	)
Accelerated Share Repurchase															(6,347	)											(258,217	)							(258,217	)
Equity compensation			—				—				—				3				3,686				—				—				—				3,686
Balances at September 30, 2005		$	406,155				420			$	1,000				80,701			$	2,427,322			$	203,973			$	(663,529	)		$	(355,753	)		$	2,019,168
Balances at December 31, 2003			—				—				1,000				100,000				2,403,429				11,025			$	—				21,802				2,437,256
Net income																							167,480												167,480
Foreign currency translation adjustments																															(13,499	)			(13,499	)
Deferred unrealized gain on derivatives, net																															(4,619	)			(4,619	)
Comprehensive income																																			149,362
Equity compensation			—				—				—				8				10,533				—				—				—				10,533
Balances at September 30, 2004			—				—			$	1,000				100,008			$	2,413,962			$	178,505			$	—			$	3,684			$	2,597,151
Balances at December 31, 2004			406,359				420				1,000				87,042				2,417,021				196,642				(405,312	)			76,454				2,692,164
Net income																							19,603												19,603
Foreign currency translation adjustments																															(50,336	)			(50,336	)
Deferred unrealized loss on derivatives																															(382,176	)			(382,176	)
Unrealized gain on available for sale securities by affiliate																															305				305
Comprehensive loss																																			(412,604	)
Issue costs			(204	)																															(204	)
4% Preferred Stock dividend																							(12,272	)											(12,272	)
Accelerated Share Repurchase															(6,347	)											(258,217	)							(258,217	)
Equity compensation			—				—				—				6				10,301				—				—				—				10,301
Balances at September 30, 2005		$	406,155				420			$	1,000				80,701			$	2,427,322			$	203,973			$	(663,529	)		$	(355,753	)		$	2,019,168

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Nine Months Ended
		September 30,
		2005				2004
		(In thousands)
Cash Flows from Operating Activities
Net income		$	19,603			$	167,480
Adjustments to reconcile net income to net cash provided/(used) by operating activities
Distributions in excess/(less) than equity in earnings of unconsolidated affiliates			1,100				(13,703	)
Depreciation and amortization			145,076				164,872
Reserve for note and interest receivable			(98	)			4,572
Amortization of debt issuance costs and debt discount			7,651				22,813
Write-off of deferred financing costs/(debt premium)			(7,701	)			15,312
Deferred income taxes			(53,605	)			67,655
Minority interest			899				1,961
Unrealized (gains)/losses on derivatives			252,256				(33,232	)
Asset impairment			6,223				42,183
Write downs and (gains)/losses on sales of equity method investments			(15,894	)			14,057
Gain on TermoRio settlement			(13,532	)			—
Gain on sale of discontinued operations			(10,735	)			(29,924	)
Amortization of power contracts and emission credits			16,118				42,822
Amortization of unearned equity compensation			8,404				10,533
Collateral deposit payments in support of energy risk management activities			(598,111	)			(28,783	)
Cash provided by changes in other working capital, net of disposition affects			128,544				146,803
Net Cash (Used)/Provided by Operating Activities			(113,802	)			595,421
Cash Flows from Investing Activities
Proceeds on sale of equity method investments			69,575				29,693
Proceeds on sale of discontinued operations			35,658				246,498
Return of capital from (investments in) equity method investments and projects			1,333				(672	)
Decrease in notes receivable, net			100,354				36,609
Capital expenditures			(45,518	)			(78,293	)
Increase/(decrease) in restricted cash and trust funds, net			17,915				(23,029	)
Net Cash Provided by Investing Activities			179,317				210,806
Cash Flows from Financing Activities
Payment of dividends to preferred stockholders			(12,272	)			—
Repayment of minority interest obligations			(3,581	)			—
Accelerated share repurchase payment, net			(250,717	)			—
Issuance of 3.625% Preferred Stock, net			246,126				—
Deferred debt issuance costs			(1,539	)			(8,497	)
Issuance expense of 4% Preferred Stock			(204	)			—
Net borrowings under revolving credit facility			80,000				—
Proceeds from issuance of long-term debt, net			249,139				531,207
Principal payments on short and long-term debt			(979,379	)			(750,343	)
Net Cash Used by Financing Activities			(672,427	)			(227,633	)
Change in Cash from Discontinued Operations			8,051				(26,486	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents			(481	)			(2,507	)
Net Increase (Decrease) in Cash and Cash Equivalents			(599,342	)			549,601
Cash and Cash Equivalents at Beginning of Period			1,103,678				549,181
Cash and Cash Equivalents at End of Period		$	504,336			$	1,098,782

See notes to condensed consolidated financial statements.

NRG ENERGY, INC.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

Note 1 — General

     NRG Energy, Inc., or “NRG”, “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 transacting in and trading of fuel and transportation services, and the marketing and trading of energy, capacity and related products in the United States and internationally.

Recent Developments – Texas Genco Acquisition

     On September 30, 2005, we entered into an Acquisition Agreement with Texas Genco LLC, a Delaware limited liability company, or Texas Genco, and each of the direct and indirect owners of Texas Genco, referred to as the Sellers. Pursuant to the Acquisition Agreement, NRG agreed to purchase all of the outstanding equity interests in Texas Genco for a total purchase price of approximately $5.825 billion, which includes the assumption by the Company of approximately $2.5 billion of indebtedness. The purchase price is subject to adjustment, and includes an equity component valued at $1.8 billion based on a price per share of $40.50 of NRG’s common stock. As a result of the Acquisition, Texas Genco will become a wholly owned subsidiary of NRG and will nearly double NRG’s U.S. generation portfolio from 12,981 Megawatts to 23,920 Megawatts.

     Pending closing of the Acquisition, Texas Genco and NRG are obligated to conduct their businesses in the ordinary course of business, to preserve their business, assets, properties and relationships, and to refrain from certain activities without prior written consent of the other party, such consent not to be unreasonably withheld or delayed. NRG is devoting substantial resources to satisfying remaining conditions precedent, arranging financing, closing the Acquisition and planning the integration of the combined companies post-closing.

     Texas Genco owns and operates 11 fossil-fuel fired electric power generation facilities in various locations in Texas, as well as a 44% undivided interest in the South Texas Project nuclear electric power generation facility, or STP. Texas Genco sells wholesale electric generation capacity, energy and ancillary services in the Electric Reliability Council of Texas market, or ERCOT.

     Of the approximately $5.825 billion payable to the Sellers upon consummation of the Acquisition, NRG will pay $4.025 billion in cash, subject to adjustment, and issue a minimum of 35,406,320 shares of NRG’s common stock. At NRG’s election, the remaining consideration may be comprised of an additional 9,038,125 shares of common stock, or at NRG’s election, the equivalent in the form of any combination of common stock, additional cash and shares of a new series of the NRG’s Cumulative Redeemable Preferred Stock, referred to as the Cumulative Preferred Stock. If issued, the liquidation preference of the Cumulative Preferred Stock will be determined with reference to the average price of NRG’s common stock over a twenty trading day period prior to the closing of the Acquisition. If NRG elects to pay all or a portion of the remaining purchase price in cash, the amount payable in cash would be calculated in the same manner. The purchase price payable by NRG is subject to adjustment based on the following items as of the closing date – the level of Texas Genco’s working capital, the amount of Texas Genco’s indebtedness and the amount of Texas Genco’s cash and cash equivalents.

     NRG expects to finance the Acquisition through a combination of a new senior secured credit facility, an unsecured high yield notes offering and the sale of common and preferred equity securities in the public markets. NRG has received a commitment letter from Morgan Stanley Senior Funding, Inc., or Morgan Stanley, and Citigroup Global Markets, Inc., or Citigroup, to provide the Company with up to $4.8 billion in senior secured debt financing, including up to $3.2 billion under a senior first priority term loan facility, up to $600 million under a senior first priority secured revolving credit facility and up to $1 billion under a senior first priority secured synthetic letter of credit facility. The commitment letter further provides for up to $5.1 billion in bridge financing to fund all necessary amounts not provided for under the senior secured debt financing. NRG does not intend to draw down on the bridge financing unless the contemplated high-yield debt financing and preferred and common equity financings are for some reason unavailable at the time of the closing. The commitment letter is subject to customary conditions to consummation, including the absence of any event or circumstance that would have a material adverse effect on the business, assets, properties, liabilities, condition (financial or otherwise) or results of operations, taken as a whole, of Texas Genco, or Texas Genco and NRG combined, since June 30, 2005.

     Each of the parties’ obligation to consummate the Acquisition is subject to certain customary conditions, including (i) the absence of any event or circumstance that would have a material adverse effect on the other party’s business, assets, properties, liabilities,

condition (financial or otherwise) or results of operations, taken as a whole, since June 30, 2005 and (ii) the receipt of required regulatory approvals, including the expiration of the required waiting period under the Hart Scott Rodino Antitrust Improvements Act, and the approval of the Nuclear Regulatory Commission and the Federal Energy Regulatory Commission. NRG could be obligated to close under the Acquisition Agreement, but Morgan Stanley and Citigroup would not be required to fund under the commitment letter, if a material adverse effect occurred with respect to Texas Genco and NRG combined, but not with respect to only Texas Genco. Subject to the foregoing conditions, the Acquisition is expected to be consummated in the first quarter of 2006.

Note 2 — Summary of Significant Accounting Policies

Basis of Presentation

     The accompanying unaudited interim condensed 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 notes required by generally accepted accounting principles for complete financial statements. The accounting policies we follow are set forth in Note 2, Summary of Significant Accounting Policies, to the Company’s financial statements in our Annual Report on Form 10-K for the year ended December 31, 2004. The following notes should be read in conjunction with such policies and other disclosures in the Form 10-K. Interim results are not necessarily indicative of results for a full year.

     In the opinion of management, the accompanying unaudited interim condensed consolidated financial statements contain all material adjustments (consisting of normal, recurring accruals) necessary to fairly present our consolidated financial position as of September 30, 2005, the results of our operations and stockholders’ equity for the nine months and three months ended September 30, 2005 and 2004, and our cash flows for the nine months ended September 30, 2005 and 2004. Certain prior-period amounts have been reclassified for comparative purposes.

Restricted Cash

     Restricted cash consists primarily of funds held to satisfy the requirements of certain debt agreements and funds held within our projects that are restricted in their use. These funds are used to pay for current operating expenses and current debt service payments, per the restrictions of the debt agreements.

Accounting Estimates

     Management of the Company is required to make certain estimates and assumptions during the preparation of the consolidated financial statements in accordance with generally accepted accounting principles. These estimates and assumptions impact the reported amount of assets and liabilities and disclosures of contingent assets and liabilities as of the date of the consolidated financial statements. They also impact the reported amount of net earnings/(loss) during any period. Actual results could differ from those estimates.

Emission Allowances and Fuel Commodities

     During the third quarter of 2005, NRG began selling its excess SO₂ emission allowances. NRG records the sale of these allowances in Operating Revenues. The cost basis of these allowances, established upon the adoption of Fresh Start, is recorded in Operating Costs and Expenses. Beginning in 2006, NRG may actively manage its SO₂ emission allowances as well as fuels. NRG will account for asset optimization activity related to emission allowances and other fuel commodities under EITF Issue No. 02-3, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities”. As such, revenues and costs for these activities would be reflected on a net basis in the consolidated statement of operations.

New Accounting Pronouncements

     During the period, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47 (FIN 47) to Financial Accounting Standard No. 143 (SFAS No. 143) governing the application of Asset Retirement Obligations. FIN 47 clarifies the term “conditional asset retirement obligation” as used in SFAS No. 143. SFAS No. 143 refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional but there may remain some uncertainty as to the timing and/or method of settlement. Accordingly, an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. The fair value of a liability for the conditional asset retirement obligation should be recognized when incurred – generally upon acquisition, construction, or development and/or

through the normal operation of the asset. SFAS No. 143 acknowledges that in some cases, sufficient information may not be available to reasonably estimate the fair value of an asset retirement obligation. FIN 47 clarifies when the company would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective for fiscal years ending after December 15, 2005 and we are currently evaluating the impact of this guidance.

     Also during the period, the SEC issued Staff Accounting Bulletin 107 (SAB 107) which addresses the application of SFAS No. 123(R) Share Based Payment, or SFAS 123(R). SAB 107 was issued to assist registrants by simplifying some of the implementation challenges of SFAS No. 123(R) while enhancing the information that investors receive. SAB 107 creates a framework that is premised on two overarching themes — considerable judgment will be required by preparers to successfully implement SFAS No. 123(R), specifically when valuing employee stock options, and that reasonable individuals, acting in good faith, may conclude differently on the fair value of employee stock options. Accordingly, situations in which there is only one acceptable fair value estimate are expected to be rare. In addition, the SEC extended the adoption date to registrants for the implementation of SFAS No. 123(R) and SAB 107 so that they may implement this guidance for their fiscal year which begins after September 15, 2005. We will adopt SFAS No.123(R) and SAB 107 on January 1, 2006.

     On March 17, 2005, the Emerging Issues Task Force, or EITF, issued EITF Issue No. 04-6, or EITF 04-6. EITF 04-6 provides that costs incurred to remove overburden and waste material to access coal seams, or stripping costs, during the production phase of a mine are variable production costs that should be included in the costs of the inventory produced during the period that the stripping costs are incurred. EITF 04-6 is effective for the first reporting period in fiscal years beginning after December 15, 2005. Our MIBRAG equity investment is a 50% interest in a mining company, which will be negatively affected by this pronouncement. Currently, MIBRAG has an asset totaling €156.7 million, approximately $188.4 million, representing the stripping costs incurred during production as of September 30, 2005. The adoption of EITF 04-6 will not have a material impact on our consolidated results of operations, but will have a material impact on our consolidated financial position. Following adoption, our investment in MIBRAG will be reduced by 50% of the above mentioned asset, approximately $94.4 million, with an offsetting charge to retained earnings.

     Also during the period, the FASB issued SFAS No. 154 “Accounting Changes and Error Corrections—a replacement of APB Opinion No. 20 and FASB Statement No. 3” (SFAS No. 154). This Statement replaces APB Opinion No. 20, Accounting Changes, and FASB Statement No. 3, Reporting Accounting Changes in Interim Financial Statements, and changes the requirements for the accounting for and reporting of a change in accounting principle. This Statement applies to all voluntary changes in accounting principle. It also applies to changes required by an accounting pronouncement in the unusual instance that the pronouncement does not include specific transition provisions. When a pronouncement includes specific transition provisions, those provisions should be followed. APB Opinion No. 20 previously required that most voluntary changes in accounting principle be recognized by including in net income of the period of the change the cumulative effect of changing to the new accounting principle. This Statement requires retrospective application to prior periods’ financial statements of changes in accounting principle for direct effects of the change, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change, and redefines restatement as the revising of previously issued financial statements to reflect the correction of an error. This Statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

     On July 12, 2005, the FASB issued Staff Position APB 18-1, “Accounting by an Investor for Its Proportionate Share of Accumulated Other Comprehensive Income of an Investee Accounted for under the Equity Method in Accordance with APB Opinion No. 18 upon a Loss of Significant Influence” (FSP APB 18-1). This guidance clarifies the application of paragraph 121 of SFAS No. 130, “Reporting Comprehensive Income” (SFAS No. 130), and clarifies that the company’s proportionate share of an investee’s equity adjustments for OCI should be offset against the carrying value of the investment at the time significant influence is lost. To the extent that the offset results in a carrying value of the investment that is less than zero, an investor should (a) reduce the carrying value of the investment to zero and (b) record the remaining balance in income. The guidance in FSP APB 18-1 is effective as of the first reporting period after July 12, 2005. Currently, this guidance does not materially affect our consolidated financial position, results of operations or cash flows.

     On June 29, 2005, the EITF issued EITF Issue No. 04-5, or EITF 04-5. EITF 04-5 provides a framework for addressing when a general partner controls a limited partnership when the limited partners have certain rights. EITF 04-5’s scope excludes a number of investment types, including limited partnerships entities that are not variable interest entities under FIN 46(R), and investments accounted for under the pro rata method of consolidation. The guidance in EITF 04-5 is effective immediately to general partners of all new limited partnerships formed and for existing limited partnerships for which the partnership agreements are modified. For general partners in all other limited partnerships, the guidance in EITF 04-5 is effective no later than the beginning of the first reporting period in fiscal years beginning after December 15, 2005. Currently, this guidance will not materially affect our consolidated financial position, results of operations or cash flows.

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.

     The assets and liabilities reported in the balance sheet as of December 31, 2004 as discontinued operations represent those of NRG McClain. The assets of NRG McClain were sold in July 2004 however certain assets and liabilities remained to effect its liquidation, and on April 29, 2005, we settled all outstanding obligations of NRG McClain. All other projects were sold as of December 31, 2004.

     For the three and nine months ended September 30, 2005, discontinued operations consisted of activity related to Northbrook New York LLC, Northbrook Energy LLC and NRG McClain. For the three and nine months ended September 30, 2004, discontinued operations included our Northbrook New York LLC, Northbrook Energy LLC, 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). McClain, PERC and LSP Energy (Batesville) are included in our Wholesale Power Generation — Other North America segment. Cobee and Hsin Yu are included in the All Other — Other International segment, Northbrook New York LLC, Northbrook Energy LLC are included in the Other North America segment and the four NEO projects are included in the All Other — Alternative Energy segment.

     Summarized results of operations of discontinued operations were as follows:

		Three Months Ended								Nine Months Ended
		September 30, 2005				September 30, 2004				September 30, 2005				September 30, 2004
		(In thousands)
Operating revenues			938				8,274				9,135				118,310
Pre-tax income from operations of discontinued operations			30				83				2,972				3,653
Income on discontinued operations, net of income taxes			9,864				10,870				12,612				25,326

     Northbrook New York LLC and Northbrook Energy LLC – On August 11, 2005, we completed the sale of Northbrook New York LLC and Northbrook Energy LLC. In exchange for the sale, we received net cash proceeds of $36 million and paid off Northbrook New York LLC’s third party debt of $17.1 million. We recognized a net pre-tax gain of $12.3 million in the third quarter of 2005.

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 condensed consolidated statement of operations include the following:

		Three Months Ended								Nine Months Ended
		September 30, 2005				September 30, 2004				September 30, 2005				September 30, 2004
		(In thousands)
Kendall		$	4,333			$	—			$	4,333			$	—
Enfield			—				—				11,561				—
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	)
Total write downs and gains/(losses) on sales of equity method investments		$	4,333			$	(13,524	)		$	15,894			$	(14,057	)

     Kendall — In December 2004, we sold our interest in Kendall to LS Power Associates, L.P., or LS Power. Under the terms of the December 2004 agreement, we retained the right to acquire a 40% interest in the plant within a 10-year period for a nominal amount, or the Call Option. Therefore, the transaction was treated as a partial sale for accounting purposes. On August 8, 2005, we executed an agreement with LS Power to sell the Call Option for $5 million. A pre-tax gain of $4.3 million was recognized in the third quarter of 2005.

     Enfield — On April 1, 2005, we completed the sale of our 25% interest in Enfield to Infrastructure Alliance Limited. The sale resulted in net pre-tax proceeds of $64.6 million. A pre-tax gain of approximately $11.6 million was recorded in the second quarter of 2005.

Note 5 — Other Charges

Corporate Relocation Charges

     On March 16, 2004, we announced plans to implement a new regional business strategy and structure. The new plan called for a reorganized management structure and corporate headquarters relocation to Princeton, New Jersey. The transition of our corporate headquarters was completed in December 2004.

     For the nine months ended September 30, 2005 and 2004, we recorded $5.7 million and $12.5 million, respectively, for charges related to our corporate relocation activities, primarily for employee severance and termination benefits, employee related transition costs and lease termination costs. These charges are classified separately in our statement of operations, in accordance with SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities”. Relocation charges for the year ended December 31, 2004 were $16.2 million. We expect to incur an additional $0.3 million to finalize certain housing relocations in the fourth quarter of 2005 of SFAS No. 146-classified expenses in connection with corporate relocation charges for a total of $22.2 million.

     A summary of the SFAS No. 146-classified expenses is as follows:

						Nine Months
		Year Ended				Ended				Yet to be				Expected
		December 31, 2004				September 30, 2005				Incurred				Total Charges
		(In thousands)
Employee related transition costs		$	8,595			$	1,710			$	348			$	10,653
Severance and termination benefits			6,505				579				—				7,084
Lease termination costs			1,067				3,362				—				4,429
Total corporate relocation charges		$	16,167			$	5,651			$	348			$	22,166

     A summary of the significant components of the restructuring liability is as follows:

		Balance at				Restructuring								Balance at
		December 31,				Related				Cash Receipts/				September 30,
		2004				Charges				(Payments)				2005
		(In thousands)
Employee related transition costs		$	(1,425	)		$	1,710			$	(645	)		$	(360	)
Severance and termination benefits			4,939				915				(5,854	)			—
Lease termination costs			796				3,362				(1,225	)			2,933
Total		$	4,310			$	5,987			$	(7,724	)		$	2,573

     As of September 30, 2005, the restructuring liability was $2.6 million the majority of which is included in other current liabilities on the condensed consolidated balance sheet. The restructuring liability excludes pension curtailment gains of $0.8 million and $0.3 million which was credited to the corporate relocation charge for the 2004 fiscal year and nine months ended September 30, 2005, respectively. All restructuring 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. Lease termination costs require that cash payments be made through the fourth quarter of 2006.

Impairment Charges

     In accordance with the guidelines of SFAS No. 144, certain events led to the review of the recoverability of some of our long-lived assets. As a result of this review, we recorded $6.0 million and $6.2 million in impairment charges for the three and nine months ended September 30, 2005, respectively, and $40.5 million and $42.2 million for the three and nine months ended September 30, 2004, respectively, which included the following:

				Three Months Ended								Nine Months Ended
				September 30,				September 30,				September 30,				September 30,
Project Name		Project Status		2005				2004				2005				2004				Fair Value Basis
				(in thousands)
Berrians I Gas Turbine Power LLC		Non-operating asset		$	6,000			$	—			$	6,000			$	—			Estimated market price
New Roads Holding LLC (turbine)		Non-operating asset- abandoned			—				740				—				2,416			Projected cash flows
Devon Power LLC		Operating at a loss			—				247				—				247			Projected cash flows
Kendall Energy LLC		Held for sale – Non-operating asset			—				24,520				—				24,520			Projected cash flows
Meriden (turbine only)		Indicative market valuation			—				15,000				—				15,000			Projected cash flows
Other					—				—				223				—
Total impairment charges				$	6,000			$	40,507			$	6,223			$	42,183

     Berrians I Gas Turbine Power LLC, or Berrians Project – Until the third quarter of 2005, NRG had been evaluating the use of an unused turbine for the Berrians Project located within our Other North America segment. We have concluded that this is most likely not feasible. As such, we have increased our efforts to sell the turbine to a third party and intend to hold an auction in the fourth quarter. As a result, we impaired the turbine based on the estimated current market price which was significantly lower than book value.

Note 6 — Investments Accounted for by the Equity Method

     We have a 50% interest in one company, West Coast Power, or WCP, which was considered significant, as defined by applicable SEC regulations.

West Coast Power LLC Summarized Results of Operations

     For the three and nine months ended September 30, 2005, we recorded equity earnings of $6.7 million and $15.2 million, respectively, for WCP after adjustments for the reversal of $2.7 million and $9.0 million, respectively, of project level depreciation expense. For the three and nine months ended September 30, 2004, we recorded equity earnings of $17.2 million and $45.1 million, respectively, 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 contract, referred to as the CDWR contract. As discussed in Note 13, Investments Accounted for by the Equity Method, in our Annual Report on Form 10-K for the year ended December 31, 2004, the amortization of an intangible is a result of pushing down the impact of Fresh Start to the project’s balance sheet, as we established a contract-based intangible asset with a one-year remaining life, consisting of the value of WCP’s CDWR energy sales contract. The following table summarizes financial information for West Coast Power, including interests owned by us and other parties for the periods shown below:

		Three Months Ended September 30								Nine Months Ended September 30
(In millions)		2005				2004				2005				2004
Operating revenues		$	61			$	183			$	219			$	535
Operating income			6				82				8				246
Income before tax			8				83				12				247

Note 7 — Accounting for Derivative Instruments and Hedging Activities

     SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities”, or SFAS No. 133, as amended, requires us to recognize all derivative instruments on the balance sheet as either assets or liabilities and measure them at fair value each reporting period. If certain conditions are met, we may be able to designate our derivatives as cash flow hedges and defer the effective portion of the change in fair value of the derivatives in Other Comprehensive Income, or OCI, and subsequently recognize in earnings when the hedged items impact income. The ineffective portion of a cash flow hedge is immediately recognized in 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. The ineffective portion of a hedging derivative instrument’s change in fair value will be immediately recognized in earnings.

     For derivatives that are neither designated as cash flow hedges or do not qualify for hedge accounting treatment, the changes in the fair value will be immediately recognized in earnings. Under the guidelines established by SFAS No. 133, as amended, certain derivative instruments may qualify for the normal purchase and sale exception and are therefore exempt from fair value accounting treatment. SFAS No. 133 applies to our energy related commodity contracts, interest rate swaps and foreign exchange contracts.

     As the Company engages principally in the trading and marketing of its generation assets, most of our commercial activities qualify for hedge accounting under the requirements of SFAS No.133. In order to so qualify, the physical generation and sale of electricity must be highly probable at inception of the trade and throughout the period it is held, as is the case with our base-load coal plants. For this reason, trades in support of the company’s peaking units will not generally qualify for hedge accounting treatment and any changes in fair value are likely to be reflected on a mark-to-market basis in the statement of operations. The majority of trades in support of our base-load coal units will normally qualify for hedge accounting treatment and any fair value movements will be reflected in the balance sheet as part of OCI.

Accumulated Other Comprehensive Income

     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, 2005:

		Energy				Interest				Foreign
		Commodities				Rate				Currency				Total
						(In thousands)
Accumulated OCI balance at June 30, 2005		$	(76,706	)		$	(2,397	)		$	—			$	(79,103	)
Unwound from OCI during the period:
— Due to unwinding of previously deferred amounts			54,676				(2,030	)			—				52,646
Mark-to-market of hedge contracts			(358,741	)			10,491				—				(348,250	)
Accumulated OCI balance at September 30, 2005		$	(380,771	)		$	6,064			$	—			$	(374,707	)
Gains/(Losses) expected to unwind from OCI during the next 12 months			(345,527	)			3,345				—				(342,182	)

     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, 2005:

		Energy				Interest				Foreign
		Commodities				Rate				Currency				Total
						(In thousands)
Accumulated OCI balance at December 31, 2004		$	5,482			$	1,987			$	—			$	7,469
Unwound from OCI during the period:
— Due to unwinding of previously deferred amounts			52,957				(1,167	)			—				51,790
Mark-to-market of hedge contracts			(439,210	)			5,244				—				(433,966	)
Accumulated OCI balance at September 30, 2005		$	(380,771	)		$	6,064			$	—			$	(374,707	)
Gains/(Losses) expected to unwind from OCI during the next 12 months			(345,527	)			3,345				—				(342,182	)

     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:

		Energy				Interest				Foreign
(Gains/(Losses) In thousands)		Commodities				Rate				Currency				Total
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	)
Mark-to-market of hedge contracts, net of tax			(1,920	)			(14,538	)			—				(16,458	)
Accumulated OCI balance at September 30, 2004		$	(9,890	)		$	4,748			$	—			$	(5,142	)

     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
(Gains/(Losses) In thousands)		Commodities				Rate				Currency				Total
Accumulated OCI balance at December 31, 2003		$	(1,953	)		$	1,600			$	(170	)		$	(523	)
Unwound from OCI during period:
— Due to unwinding of previously deferred amounts			9,756				3,751				170				13,677
Mark-to-market of hedge contracts, net of tax			(17,693	)			(603	)			—				(18,296	)
Accumulated OCI balance at September 30, 2004		$	(9,890	)		$	4,748			$	—			$	(5,142	)

     Losses of $52.6 million and of $51.8 million were reclassified from OCI to current period earnings during the three and nine months ended September 30, 2005, respectively, 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, 2005 we recorded losses in OCI of approximately $348.3 million and losses of $433.9 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, 2005 was an unrecognized loss of approximately $374.7 million. We expect $342.2 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 derivatives that do not qualify for hedge accounting treatment on our statement of operations for the three months ended September 30, 2005:

		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	(164,255	)		$	—			$	—			$	(164,255	)
Cost of operations			6,457				—				—				6,457
Total statement of operations impact before tax		$	(170,712	)		$	—			$	—			$	(170,712	)

     The following tables summarize the pre-tax effects of derivatives do not qualify for hedge accounting treatment on our statement of operations for the nine months ended September 30, 2005:

		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	(245,864	)		$	—			$	—			$	(245,864	)
Equity in earnings of unconsolidated subsidiaries			11,868				—				—				11,868
Cost of operations			5,073				—				—				5,073
Total statement of operations impact before tax		$	(239,069	)		$	—			$	—			$	(239,069	)

     The following tables summarize the pre-tax effects of derivatives do not qualify for hedge accounting treatment on our statement of operations for the three months ended September 30, 2004:

		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	(3,809	)		$	—			$	—			$	(3,809	)
Equity in earnings of unconsolidated subsidiaries			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 derivatives that do not qualify for hedge accounting treatment on our statement of operations for the nine months ended September 30, 2004:

		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	3,659			$	—			$	—			$	3,659
Equity in earnings of unconsolidated subsidiaries			22,601				414				—				23,015
Cost of operations			(465	)			—				—				(465	)
Other income			—				411				—				411
Total statement of operations impact before tax		$	26,725			$	825			$	—			$	27,550

Energy Related Commodities

     As part of our risk management activities, we manage the commodity price risk associated with our competitive supply activities and the price risk associated with power sales from our electric generation facilities. In doing so, we may enter into a variety of derivative and non-derivative instruments, including the following:

	•		Forward contracts, which commit us to purchase or sell energy commodities in the future.
	•		Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument.
	•		Swap agreements, which require payments to or from counter-parties based upon the differential between two prices for a predetermined contractual (notional) quantity.
	•		Option contracts, which convey the right to buy or sell a commodity, financial instrument, or index at a predetermined price.

     The objectives for entering into such hedges include:

	•		Fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on our electric generation operations.
	•		Fixing the price of a portion of anticipated fuel purchases for the operation of our power plants. • Fixing the price of a portion of anticipated energy purchases to supply our load-serving customers.
	•		Fixing the price of a portion of anticipated energy purchases to supply our load-serving customers.

     Ineffectiveness will result from a difference in the relative price movements between a financial transaction and the underlying physical pricing point. If this difference is large enough, it will cause an entity to discontinue the use of hedge accounting. During the three and nine months ended September 30, 2005 our pre-tax earnings were affected by an unrealized loss of $0.4 million due to the ineffectiveness associated with financial forward contracted electric sales.

     During the three and nine months ended September 30, 2005, our pre-tax earnings were affected by an unrealized loss of $170.7 million and $250.9 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. These amounts exclude the effect of unrealized gains and losses recorded by equity investees.

     During the three and nine months ended September 30, 2004, our pre-tax earnings were affected by an unrealized loss of $1.7 million and $4.1 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. These amounts exclude the affect of unrealized gains and losses recorded by equity investee’s.

     During the three and nine months ended September 30, 2005, we reclassified losses of $54.7 million and $53.0 million, respectively, from OCI to current period earnings and expect to reclassify approximately $345.5 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

     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.

     At September 30, 2005, we had hedge and non-hedge energy related commodity contracts extending through March 2025.

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. Any ineffectiveness on interest rate swaps during the three and nine months ended September 30, 2005 and 2004 was immaterial to our financial results.

     During the three and nine months ended September 30, 2004, pre-tax earnings were increased by an unrealized gain of $0 million and $0.4 million, respectively, related to the change in fair value of one interest rate related derivative instrument. This instrument is a $400 million floating to fixed interest rate swap, which was not designated as an effective hedge of the expected cash flows at March 31, 2004. As of April 1, 2004, this instrument was designated as a cash flow hedge under SFAS No. 133. As a result, subsequent changes to its fair value will be deferred and recorded as part of other comprehensive income.

     During the three and nine months ended September 30, 2005, we reclassified gains of $2.0 million and $1.2 million, respectively, from OCI to current period earnings and expect to reclassify approximately $3.3 million of deferred gains to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

     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.

     At September 30, 2005, we had interest rate derivative instruments extending through September 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. As of September 30, 2005, the results of any outstanding foreign currency exchange contracts were immaterial to our financial results.

Note 8 — Long-Term Debt

NRG Energy Corporate Debt

     In January 2005 and March 2005, we used existing cash to purchase, at market prices, $25 million and $15.8 million, respectively, in face value of our 8% Second Priority Notes, or Second Priority Notes. We paid $3.4 million in fees and market premiums on the repurchased notes which were recorded to refinancing expense, and an additional $0.7 million of accrued interest. On February 4, 2005, we redeemed $375.0 million in Second Priority Notes and paid $30.0 million for the early redemption premium on the redeemed notes which was recorded to refinancing expense. In addition, we paid $4.1 million in accrued but unpaid interest on the redeemed notes and $0.4 million in accrued but unpaid liquidated damages on the redeemed notes. On July 28, 2005, we closed the registered exchange offer to exchange up to $1.35 billion aggregate principal amount of the Second Priority Notes, which were registered under the Securities Act of 1933, as amended, for all outstanding Second Priority Notes that were issued and sold by NRG in December 2003 and January 2004 in private placement offerings. $1,348,508,000 in aggregate principal amount or 99.89% of the outstanding Second Priority Notes were exchanged. On September 12, 2005, we redeemed $228.8 million in Second Priority Notes and paid $18.3 million for the early redemption premium on the redeemed notes which was recorded to refinancing expense. During the nine months ended September 30, 2005, we redeemed or repurchased $644.6 million of our Second Priority Notes, and paid $51.7 million in fees and market premiums.

     As of September 30, 2005, we had $80.0 million drawn under our $150.0 million corporate revolving credit facility. As of November 3, 2005, this facility was undrawn.

Certain Events Related to Project-Level Debt

     In February 2005, NRG Flinders amended its debt facility of AUD 279.4 million (approximately US $218.5 million) in floating-rate debt. The amendment extended the maturity to February 2017, reduced borrowing costs and reserve requirements, reduced debt service coverage ratios, removed mandatory cash sharing arrangements, and made other minor modifications to terms and conditions. The facility includes an AUD 20.0 million (US $15.6 million) working capital and performance bond facility, under which AUD 14.0 million (US $10.6 million) in performance bonds and letters of credit have been issued as of September 30, 2005. An interim arrangement to indemnify the Australia New Zealand Bank, or ANZ, of up to AUD 15.5 million (US $11.8 million) was terminated on May 17, 2005. NRG Flinders is required to maintain interest-rate hedging contracts on a rolling 5-year basis at a minimum level of 60% of principal outstanding. Upon execution of the amendment, a voluntary principal prepayment of AUD 50 million (US $39.1 million) was made. On March 31, 2005 Flinders made voluntary prepayments of AUD 10.5 million (US $8.1 million) and on June 30, 2005, Flinders’ made scheduled repayments of AUD 13.1 million (US $10 million), respectively. On August 25, 2005, Flinders redrew AUD 60.5 million (US $46.1 million). As of September 30, 2005, AUD 246.3 million (US $187.9 million) was outstanding.

Note 9 — Earnings Per Share

     Basic earnings per common share were computed by dividing net income less accumulated preferred stock dividends 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. 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 nonvested restricted stock units 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. The deferred stock units 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 if-converted method. The performance units 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. The reconciliation of basic earnings per common share to diluted earnings per common share is shown in the following table:

		Three Months Ended September 30								Nine Months Ended September 30
		2005				2004				2005				2004
		(In thousands, except per share data)
Basic earnings per share
Numerator:
Income (loss) from continuing operations		$	(36,745	)		$	43,351			$	6,991			$	142,154
Preferred stock dividends			(5,459	)			—				(13,859	)			—
Net (loss) income available to common stockholders from continuing operations			(42,204	)			43,351				(6,868	)			142,154
Discontinued operations, net of tax			9,864				10,870				12,612				25,326
Net income (loss) available to common stockholders		$	(32,340	)		$	54,221			$	5,744			$	167,480
Denominator:
Weighted average number of common shares outstanding			83,529				100,101				85,860				100,066
Basic earnings per share:
Income (loss) from continuing operations		$	(0.51	)		$	0.43			$	(0.08	)		$	1.42
Discontinued operations, net of tax			0.12				0.11				0.15				0.25
Net income (loss)		$	(0.39	)		$	0.54			$	0.07			$	1.67
Diluted earnings per share
Numerator:
Net income (loss) available to common stockholders from continuing operations		$	(42,204	)		$	43,351			$	(6,868	)		$	142,154
Discontinued operations, net of tax			9,864				10,870				12,612				25,326
Net income (loss) available to common stockholders		$	(32,340	)		$	54,221			$	5,744			$	167,480
Denominator:
Weighted average number of common shares outstanding			83,529				100,101				85,860				100,066
Incremental shares attributable to the issuance of nonvested restricted stock units (treasury stock method)			—				496				—				262
Incremental shares attributable to the issuance of nonvested nonqualifying stock options (treasury stock method)			—				19				—				—
Total dilutive shares			83,529				100,616				85,860				100,328
Diluted earnings per share:
Income (loss) from continuing operations		$	(0.51	)		$	0.43			$	(0.08	)		$	1.42
Discontinued operations, net of tax			0.12				0.11				0.15				0.25
Net income (loss)		$	(0.39	)		$	0.54			$	0.07			$	1.67