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: June 30, 2005		Commission File Number: 001-15891

NRG Energy, Inc.

(Exact name of Registrant as specified in its charter)

Delaware		41-1724239
(State or other jurisdiction		(I.R.S. Employer
of incorporation or organization)		Identification No.)
211 Carnegie Center
Princeton, New Jersey		08540
(Address of principal executive offices)		(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 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 August 3, 2005, there were 87,047,034 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			38
Item 3 Quantitative and Qualitative Disclosures About Market Risk			60
Item 4 Controls and Procedures			63
Part II — OTHER INFORMATION
Item 1. Legal Proceedings			64
Item 2. Unregistered Sale of Equity Securities and Use of Proceeds			64
Item 3. Defaults Upon Senior Securities			64
Item 4. Submission of Matters to a Vote of Security Holders			64
Item 5. Other Information			64
Item 6. Exhibits			65
SIGNATURES			66
Exhibit Index			67
EX-10.1: FORM OF LONG TERM PERFORMANCE UNIT AGREEMENT
EX-10.2: FIRST AMENDMENT TO CREDIT AGREEMENT
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 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:

	•		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 borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward;
	•		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; and
	•		Our ability to complete the preferred stock issuance and share repurchase as described in this Form 10-Q.

     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								Six Months
		Ended								Ended
		June 30,				June 30,				June 30,				June 30,
		2005				2004				2005				2004
		(In thousands, except for per share amounts)
Operating Revenues
Revenues from majority-owned operations		$	584,567			$	573,623			$	1,185,709			$	1,173,888
Operating Costs and Expenses
Cost of majority-owned operations			436,470				353,258				889,392				735,011
Depreciation and amortization			47,749				53,168				96,173				108,174
General, administrative and development			53,164				45,746				103,058				82,138
Other charges
Corporate relocation charges			456				5,645				3,911				6,761
Reorganization items			—				(2,661	)			—				3,589
Impairment charges			223				1,676				223				1,676
Total operating costs and expenses			538,062				456,832				1,092,757				937,349
Operating Income			46,505				116,791				92,952				236,539
Other Income (Expense)
Minority interest in earnings of consolidated subsidiaries			(407	)			(201	)			(881	)			(709	)
Equity in earnings of unconsolidated affiliates			16,460				46,101				53,424				63,814
Write downs and gains/(losses) on sales of equity method investments			11,561				1,205				11,561				(533	)
Other income, net			7,654				8,051				33,156				11,708
Refinancing expense			—				—				(25,024	)			(30,417	)
Interest expense			(50,560	)			(66,225	)			(106,551	)			(128,954	)
Total other expense			(15,292	)			(11,069	)			(34,315	)			(85,091	)
Income From Continuing Operations Before Income Taxes			31,213				105,722				58,637				151,448
Income Tax Expense			8,081				36,322				12,883				50,602
Income From Continuing Operations			23,132				69,400				45,754				100,846
Income from discontinued operations, net of income taxes			734				13,624				730				12,413
Net Income			23,866				83,024				46,484				113,259
Preference stock dividends			4,200				—				8,072				—
Income Available for Common Stockholders		$	19,666			$	83,024			$	38,412			$	113,259
Weighted Average Number of Common Shares Outstanding — Basic			87,046				100,080				87,045				100,051
Income From Continuing Operations per Weighted Average Common Share — Basic		$	0.22			$	0.69			$	0.43			$	1.01
Income From Discontinued Operations per Weighted Average Common Share — Basic			0.01				0.14				0.01				0.12
Net Income per Weighted Average Common Share — Basic		$	0.23			$	0.83			$	0.44			$	1.13
Weighted Average Number of Common Shares Outstanding — Diluted			87,775				100,478				87,729				100,214
Income From Continuing Operations per Weighted Average Common Share — Diluted		$	0.21			$	0.69			$	0.42			$	1.01
Income From Discontinued Operations per Weighted Average Common Share — Diluted			0.01				0.14				0.01				0.12
Net Income per Weighted Average Common Share — Diluted		$	0.22			$	0.83			$	0.43			$	1.13

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

		June 30,				December 31,
		2005				2004
		(unaudited)
		(In thousands)
ASSETS
Current Assets
Cash and cash equivalents		$	823,161			$	1,110,045
Restricted cash			87,248				112,824
Accounts receivable, less allowance for doubtful accounts			313,660				272,101
Current portion of notes receivable			25,100				85,447
Income taxes receivable			38,877				37,484
Inventory			228,995				248,010
Derivative instruments valuation			59,524				79,759
Prepayments and other current assets			294,062				169,608
Deferred income taxes			1,262				—
Current assets — discontinued operations			—				3,010
Total current assets			1,871,889				2,118,288
Property, plant and equipment, net of accumulated depreciation of $301,371 and $207,536			3,308,650				3,374,551
Other Assets
Equity investments in affiliates			637,881				734,950
Notes receivable, less current portion, less reserve for uncollectible notes of $3,794 and $8,196			723,461				804,522
Intangible assets, net			275,854				294,350
Derivative instruments valuation			13,415				41,787
Funded letter of credit			350,000				350,000
Other non-current assets			100,514				111,580
Total other assets			2,101,125				2,337,189
Total Assets		$	7,281,664			$	7,830,028
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of long-term debt and capital leases		$	90,745			$	512,252
Accounts payable			150,688				171,722
Derivative instruments valuation			129,623				16,772
Deferred income taxes			—				334
Other bankruptcy settlement			177,424				175,576
Accrued expenses and other current liabilities			237,903				209,923
Current liabilities — discontinued operations			—				1,362
Total current liabilities			786,383				1,087,941
Other Liabilities
Long-term debt and capital leases			3,120,206				3,253,866
Deferred income taxes			109,438				134,325
Derivative instruments valuation			153,464				148,445
Out-of-market contracts			309,129				318,664
Other non-current liabilities			195,309				187,438
Non-current liabilities — discontinued operations			—				1,081
Total non-current liabilities			3,887,546				4,043,819
Total Liabilities			4,673,929				5,131,760
Minority Interest			7,084				6,104
Commitments and Contingencies
Stockholders’ Equity
4% Convertible Perpetual Preferred Stock; $.01 par value; 10,000,000 shares authorized, 420,000 outstanding at June 30, 2005 and December 31, 2004 (shown at liquidation value, net of issuance costs)			406,155				406,359
Common Stock; $.01 par value; 500,000,000 shares authorized; 87,045,104 and 87,041,935 outstanding at June 30, 2005 and December 31, 2004			1,000				1,000
Additional paid-in capital			2,423,636				2,417,021
Retained earnings			235,054				196,642
Less treasury stock, at cost — 13,000,000 shares			(405,312	)			(405,312	)
Accumulated other comprehensive income/(loss)			(59,882	)			76,454
Total stockholders’ equity			2,600,651				2,692,164
Total Liabilities and Stockholders’ Equity		$	7,281,664			$	7,830,028

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
For the Three and Six Months Ended June 30, 2005 and June 30, 2004
(Unaudited)

																														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 March 31, 2004		$	—				—			$	1,000				100,000			$	2,406,771			$	41,260			$	—			$	(3,176	)		$	2,445,855
Net income																							83,024												83,024
Foreign currency translation adjustments																															(33,520	)			(33,520	)
Deferred unrealized gain on derivatives, net																															36,739				36,739
Comprehensive income																																			86,243
Equity based compensation			—				—				—				7				3,980				—				—				—				3,980
Balances at June 30, 2004		$	—				—			$	1,000				100,007			$	2,410,751			$	124,284			$	—			$	43			$	2,536,078
Balances at March 31, 2005		$	406,306				420			$	1,000				87,045			$	2,420,982			$	215,388			$	(405,312	)		$	(28,274	)		$	2,610,090
Net income																							23,866												23,866
Foreign currency translation adjustments																															(26,923	)			(26,923	)
Deferred unrealized loss on derivatives, net																															(4,685	)			(4,685	)
Comprehensive loss																																			(7,742	)
Issue costs			(151	)																															(151	)
4% preferred stock dividend																							(4,200	)											(4,200	)
Equity based compensation			—				—				—				—				2,654				—				—				—				2,654
Balances at June 30, 2005		$	406,155				420			$	1,000				87,045			$	2,423,636			$	235,054			$	(405,312	)		$	(59,882	)		$	2,600,651

																														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 December 31, 2003		$	—				—			$	1,000				100,000			$	2,403,429			$	11,025			$	—			$	21,802			$	2,437,256
Net income																							113,259												113,259
Foreign currency translation adjustments																															(35,933	)			(35,933	)
Deferred unrealized gain on derivatives, net																															14,174				14,174
Comprehensive income																																			91,500
Equity based compensation			—				—				—				7				7,322				—				—				—				7,322
Balances at June 30, 2004		$	—				—			$	1,000				100,007			$	2,410,751			$	124,284			$	—			$	43			$	2,536,078
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																							46,484												46,484
Foreign currency translation adjustments																															(49,764	)			(49,764	)
Deferred unrealized loss on derivatives, net																															(86,572	)			(86,572	)
Comprehensive loss																																			(89,852	)
Issue costs			(204	)																															(204	)
4% preferred stock dividend																							(8,072	)											(8,072	)
Equity based compensation			—				—				—				3				6,615				—				—				—				6,615
Balances at June 30, 2005		$	406,155				420			$	1,000				87,045			$	2,423,636			$	235,054			$	(405,312	)		$	(59,882	)		$	2,600,651

See notes to condensed consolidated financial statements.

NRG ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

		Six Months Ended
		June 30,
		2005				2004
		(In thousands)
Cash Flows from Operating Activities
Net income		$	46,484			$	113,259
Adjustments to reconcile net income to net cash provided by operating activities
Distributions in excess of equity in earnings of unconsolidated affiliates			15,925				4,751
Depreciation and amortization			96,173				113,499
Reserve for note and interest receivable			(98	)			—
Amortization of debt issuance costs and debt discount			4,958				16,543
Write-off of deferred financing costs/(debt premium)			(8,413	)			15,312
Deferred income taxes			(3,625	)			49,384
Minority interest			881				2,089
Unrealized (gains)/losses on derivatives			81,710				(21,458	)
Asset impairment			223				1,676
Write downs and (gains)/losses on sales of equity method investments			(11,561	)			533
Gain on TermoRio settlement			(13,532	)			—
Gain on sale of discontinued operations			—				(13,012	)
Amortization of power contracts and emission credits			15,140				34,517
Amortization of unearned equity compensation			4,718				7,322
Cash used by changes in working capital, net of disposition affects			(137,464	)			(7,058	)
Net Cash Provided by Operating Activities			91,519				317,357
Cash Flows from Investing Activities
Proceeds on sale of equity method investments			64,575				29,693
Proceeds on sale of discontinued operations			—				59,190
Return of capital from (investments in) equity method investments and projects			1,291				(566	)
Decrease in notes receivable, net			92,904				15,208
Capital expenditures			(36,537	)			(64,676	)
Increase/(decrease) in restricted cash and trust funds, net			26,313				(37,291	)
Net Cash Provided by Investing Activities			148,546				1,558
Cash Flows from Financing Activities
Proceeds from issuance of long-term debt, net			204,141				490,631
Payment of dividends to preferred stockholders			(8,072	)			—
Deferred debt issuance costs			(1,582	)			(8,497	)
Issuance expense of preferred shares			(204	)			—
Principal payments on short and long-term debt			(721,548	)			(567,806	)
Net Cash Used by Financing Activities			(527,265	)			(85,672	)
Change in Cash from Discontinued Operations			1,685				10,822
Effect of Exchange Rate Changes on Cash and Cash Equivalents			(1,369	)			25,588
Net Increase (Decrease) in Cash and Cash Equivalents			(286,884	)			269,653
Cash and Cash Equivalents at Beginning of Period			1,110,045				551,223
Cash and Cash Equivalents at End of Period		$	823,161			$	820,876

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 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.

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 June 30, 2005, the results of our operations and stockholders’ equity for the six months and three months ended June 30, 2005 and 2004, and our cash flows for the six months ended June 30, 2005 and 2004. Certain prior-year 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 during any period. Actual results could differ from those estimates.

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). 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 June 15, 2005.

     On March 17, 2005, the Emerging Issues Task Force (EITF) issued EITF Issue No. 04-6 (EITF 04-6). EITF 04-6 provides that stripping costs incurred 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 €153 million, approximately $185.4 million, representing the stripping costs incurred during production as of June 30, 2005. We are currently evaluating the implementation of this guidance.

     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.

     Also during the period, the FASB issued Staff Position 150-1 “Issuer’s Accounting under FASB Statement No. 150 for Freestanding and Other Similar Instruments on Shares That Are Redeemable” (FSP FAS 150-1). This Staff Position clarifies the application of paragraph 11 of SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” (SFAS No. 150), and requires classification as a liability of warrants for an issuer’s equity shares that are puttable under paragraph 11 of SFAS No. 150 because the warrants embody obligations to repurchase the issuer’s shares and may require a transfer of assets. The guidance in FSP FAS 150-1 applies to the first reporting period beginning after June 30, 2005. If the guidance in this FSP results in changes to previously reported information, the cumulative effect shall be reported according to the transition provisions of SFAS No. 150 in the first reporting period beginning after June 30, 2005. Currently, this guidance does not materially affect our consolidated financial position, results of operations or cash flows.

     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.

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.

     Statement of Financial Accounting Standards, or 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 condensed consolidated statements of operations. In accordance with SFAS No. 144, assets held for sale will not be depreciated commencing with their classification as such.

     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 six months ended June 30, 2005, discontinued operations consisted of activity related to NRG McClain as noted above. For the three and six months ended June 30, 2004, discontinued operations included our NRG McClain LLC; Penobscot Energy Recovery Company, or PERC; Compania Boliviana De Energia Electrica S.A. Bolivian Power Company Limited, or Cobee; Hsin Yu, 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 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				Three Months				Six Months				Six Months
		Ended				Ended				Ended				Ended
		June 30, 2005				June 30, 2004				June 30, 2005				June 30, 2004
		(In thousands)
Operating revenues		$	—			$	43,309			$	—			$	102,185
Pre-tax income from operations of discontinued operations			734				1,732				730				1,502
Income on discontinued operations, net of income taxes			734				13,624				730				12,413

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				Three Months				Six Months				Six Months
		Ended				Ended				Ended				Ended
		June 30, 2005				June 30, 2004				June 30, 2005				June 30, 2004
		(In thousands)
Enfield		$	11,561			$	—			$	11,561			$	—
Calpine Cogeneration			—				500				—			$	735
Loy Yang			—				705				—				(1,268	)
Total write downs and gains/(losses) on sales of equity method investments		$	11,561			$	1,205			$	11,561			$	(533	)

     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.

     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 — During the first quarter of 2004, we wrote down our investment in Loy Yang by $2.0 million due to recent estimates of the expected sales proceeds. In April 2004, we completed the sale of our 25.4% interest in Loy Yang to Great Energy Alliance Corporation, which resulted in net cash proceeds of $26.7 million and a gain of $0.7 million. This resulted in an adjusted loss of $1.3 million for the six months ended June 30, 2004.

Note 5 —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 six months ended June 30, 2005 and 2004, we recorded $3.9 million and $6.8 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 $1.0 million in the third and fourth quarters of 2005 of SFAS No. 146-classified expenses in connection with corporate relocation charges for a total of $21.1 million.

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

						Six Months
		Year Ended				Ended				Yet to be				Expected
		December 31, 2004				June 30, 2005				Incurred				Total Charges
		(In thousands)
Employee related transition costs		$	8,595			$	931			$	424			$	9,950
Severance and termination benefits			6,505				172				—				6,677
Lease termination costs			1,067				2,808				554				4,429
Total corporate relocation charges		$	16,167			$	3,911			$	978			$	21,056

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

		Balance at				Restructuring								Balance at
		December 31,				Related				Cash Receipts/				June 30,
		2004				Charges				(Payments)				2005
		(In thousands)
Employee related transition costs		$	(1,425	)		$	931			$	452			$	(42	)
Severance and termination benefits			4,939				507				(4,895	)			551
Lease termination costs			796				2,808				(631	)			2,973
Total		$	4,310			$	4,246			$	(5,074	)		$	3,482

     As of June 30, 2005, the restructuring liability was $3.5 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 six months ended June 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. Severance and termination benefits require that cash payments be made through the fourth quarter of 2005. Lease termination costs require that cash payments be made through the fourth quarter of 2006.

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 six months ended June 30, 2005, we recorded equity earnings of $4.4 million and $8.5 million, respectively, for WCP after adjustments for the reversal of $3.1 million and $6.3 million, respectively, of project level depreciation expense. For the three and six months ended June 30, 2004, we recorded equity earnings of $21.9 million and $27.9 million, respectively, after

adjustments for the reversal of $5.6 million and $7.6 million, respectively, of project level depreciation expense, offset by a decrease in earnings related to $30.6 million and $61.6 million, respectively, of amortization of the intangible asset for the California Department of Water Resources, or CDWR contract. As 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								Six Months Ended
(In millions)		June 30, 2005				June 30, 2004				June 30, 2005				June 30, 2004
Operating revenues		$	72			$	185			$	158			$	352
Operating income			2				94				2				164
Income before tax			2				94				4				164

Note 7 — Accounting for Derivative Instruments and Hedging Activities

     SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (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 Accumulated Other Comprehensive Income (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 Other Comprehensive Income.

Accumulated Other Comprehensive Income (OCI)

     The following table summarizes the effects of SFAS No. 133 on our OCI balance attributable to hedged derivatives for the three months ended June 30, 2005 before income taxes:

		Energy				Interest				Foreign
		Commodities				Rate				Currency				Total
		(In thousands)
Accumulated OCI balance at March 31, 2005		$	(87,043	)		$	12,625			$	—			$	(74,418	)
Unwound from OCI during the period:
— Due to unwinding of previously deferred amounts			1,036				259				—				1,295
Mark-to-market of hedge contracts (net of tax)			9,301				(15,281	)			—				(5,980	)
Accumulated OCI balance at June 30, 2005		$	(76,706	)		$	(2,397	)		$	—			$	(79,103	)
Gains/(Losses) expect to unwind from OCI during the next 12 months			(59,480	)			5,735				—				(53,745	)

     The following table summarizes the effects of SFAS No. 133 on our OCI balance attributable to hedged derivatives for the six months ended June 30, 2005 before income taxes:

		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			(1,719	)			863				—				(856	)
Mark-to-market of hedge contracts (net of tax)			(80,469	)			(5,247	)			—				(85,716	)
Accumulated OCI balance at June 30, 2005		$	(76,706	)		$	(2,397	)		$	—			$	(79,103	)
Gains/(Losses) expect to unwind from OCI during the next 12 months			(59,480	)			5,735				—				(53,745	)

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

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

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

		Energy				Interest				Foreign
(Gains/(Losses) In thousands)		Commodities				Rate				Currency				Total
Accumulated OCI balance at December 31, 2003		$	(1,953	)		$	1,600			$	(170	)		$	(523	)
Unwound from OCI during period:
— Due to unwinding of previously deferred amounts			8,784				7,058				170				16,012
Mark-to-market of hedge contracts			(15,773	)			13,935				—				(1,838	)
Accumulated OCI balance at June 30, 2004		$	(8,942	)		$	22,593			$	—			$	13,651

     Losses of $1.3 million and gains of $0.9 million were reclassified from OCI to current period earnings during the three and six months ended June 30, 2005 due to the unwinding of previously deferred amounts. These amounts are recorded on the same line in the statement of operations in which the hedged items are recorded. Also during the three and six months ended June 30, 2005 we recorded losses in OCI of approximately $6.0 million and losses of $85.7 million, respectively, related to changes in the fair values of derivatives accounted for as hedges. The net balance in OCI relating to SFAS No. 133 as of June 30, 2005 was an unrecognized loss of approximately $79.1 million. We expect $53.7 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 on our statement of operations for the three months ended June 30, 2005:

		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	5,604			$	—			$	—			$	5,604
Equity in earnings of unconsolidated subsidiaries			—				—				—				—
Cost of operations			3,044				—				—				3,044
Total statement of operations impact before tax		$	2,560			$	—			$	—			$	2,560

     The following tables summarize the pre-tax effects of non-hedge derivatives on our statement of operations for the six months ended June 30, 2005:

		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	(81,609	)		$	—			$	—			$	(81,609	)
Equity in earnings of unconsolidated subsidiaries			11,868				—				—				11,868
Cost of operations			(1,384	)			—				—				(1,384	)
Interest expense			—				—				—				—
Total statement of operations impact before tax		$	(68,357	)		$	—			$	—			$	(68,357	)
The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the three months ended June 30, 2004:
		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	6,572			$	—			$	—			$	6,572
Equity in earnings of unconsolidated subsidiaries			9,733				560				—				10,293
Cost of operations			1,129				—				—				1,129
Total statement of operations impact before tax		$	15,176			$	560			$	—			$	15,736
The following tables summarize the pre-tax effects of non-hedge derivatives and derivatives that no longer qualify as hedges on our statement of operations for the six months ended June 30, 2004:
		Energy								Foreign
(Gains/(Losses) In thousands)		Commodities				Interest Rate				Currency				Total
Revenue from majority-owned subsidiaries		$	7,468			$	—			$	—			$	7,468
Equity in earnings of unconsolidated subsidiaries			8,506				629				—				9,135
Cost of operations			1,632				—				—				1,632
Other income			—				411				—				411
Total statement of operations impact before tax		$	14,342			$	1,040			$	—			$	15,382

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.

     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 six months ended June 30, 2005 our pre-tax earnings were affected by an unrealized loss of $1.7 million due to the ineffectiveness associated with financial forward contracted electric sales.

     During the three and six months ended June 30, 2005, our pre-tax earnings were affected by an unrealized gain of $2.6 million and unrealized losses of $80.2 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 six months ended June 30, 2004, our pre-tax earnings were increased by an unrealized gain of $5.4 million and $5.8 million, respectively, associated with changes in the fair value of energy related derivative instruments not accounted for as hedges in accordance with SFAS No. 133. These amounts exclude the affect of unrealized gains and losses recorded by equity investee’s.

     During the three and six months ended June 30, 2005, we reclassified losses of $1.0 million and gains of $1.7 million, respectively, from OCI to current period earnings and expect to reclassify approximately $59.5 million of deferred losses to earnings during the next twelve months on energy related derivative instruments accounted for as hedges.

     During the three and six months ended June 30, 2004, we reclassified losses of $9.4 million and $8.8 million, respectively, from OCI to current period earnings.

     At June 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 six months ended June 30, 2005 and 2004 was immaterial to our financial results.

     During the three and six months ended June 30, 2004, pre-tax earnings were increased by an unrealized gain of $0 million and $0.4 million, respectively, related to the change in fair value of one interest rate related derivative instrument. This instrument is a $400 million floating to fixed interest rate swap, which was not designated as an effective hedge of the expected cash flows at 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 six months ended June 30, 2005, we reclassified losses of $0.3 million and $0.9 million, respectively, from OCI to current period earnings and expect to reclassify approximately $5.7 million of deferred gains to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

     During the three and six months ended June 30, 2004, we reclassified losses of $3.3 million and $7.1 million, respectively, from OCI to current period earnings and expect to reclassify immaterial amounts to earnings during the next twelve months associated with interest rate swaps accounted for as hedges.

     At June 30, 2005, we had interest rate derivative 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. As of June 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 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 June 17, 2005, we announced the commencement of a registered exchange offer to exchange up to $1.35 billion aggregate principal amount of the 8% Second Priority Notes, which have been registered under the Securities Act of 1933, as amended, for all outstanding 8% Second Priority Notes that were issued and sold by NRG in December 2003 and January 2004 in private placement offerings. The sole purpose of this exchange offer was to fulfill our obligations with respect to the registration of the notes issued in the private placements. The exchange offer expired on July 25, 2005 and closed on July 28, 2005.

     As of June 30, 2005 and August 3, 2005, our $150.0 million corporate revolving credit facility remained 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 June 30, 2005. An interim arrangement to indemnify 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, reducing the outstanding amount to AUD 185.8 million (US $141.5 million). NRG Flinders retains the right to redraw these amounts at any time.

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 reconciliation of basic earnings per common share to diluted earnings per common share is shown in the following table:

		Three Months Ended								Six Months Ended
		June 30, 2005				June 30, 2004				June 30, 2005				June 30, 2004
		(In thousands, except per share data)
Basic earnings per share
Numerator:
Income from continuing operations		$	23,132			$	69,400			$	45,754			$	100,846
Preferred stock dividends			(4,200	)			—				(8,400	)			—
Net income available to common stockholders from continuing operations			18,932				69,400				37,354				100,846
Discontinued operations, net of tax			734				13,624				730				12,413
Net income available to common stockholders		$	19,666			$	83,024			$	38,084			$	113,259
Denominator:
Weighted average number of common shares outstanding			87,046				100,080				87,045				100,051
Basic earnings per share:
Income from continuing operations		$	0.22			$	0.69			$	0.43			$	1.01
Discontinued operations, net of tax			0.01				0.14				0.01				0.12
Net income		$	0.23			$	0.83			$	0.44			$	1.13

		Three Months Ended								Six Months Ended
		June 30, 2005				June 30, 2004				June 30, 2005				June 30, 2004
		(In thousands, except per share data)
Diluted earnings per share
Numerator
Net income available to common stockholders from continuing operations		$	18,932			$	69,400			$	37,354			$	100,846
Discontinued operations, net of tax			734				13,624				730				12,413
Net income available to common stockholders		$	19,666			$	83,024			$	38,084			$	113,259
Denominator:
Weighted average number of common shares outstanding			87,046				100,080				87,045				100,051
Incremental shares attributable to the issuance of nonvested restricted stock units (treasury stock method)			396				398				378				163
Incremental shares attributable to the assumed conversion of deferred stock units (if-converted method)			112				—				90				—
Incremental shares attributable to the issuance of nonvested nonqualifying stock options (treasury stock method)			221				—				216				—
Total dilutive shares			87,775				100,478				87,729				100,214
Diluted earnings per share:
Income from continuing operations		$	0.21			$	0.69			$	0.42			$	1.01
Discontinued operations, net of tax			0.01				0.14				0.01				0.12
Net income		$	0.22			$	0.83			$	0.43			$	1.13