EX-99.1


		NEWS RELEASE

FOR IMMEDIATE RELEASE

NRG Energy, Inc. Reports Second Quarter 2005 Results;
Announces $250 Million Share Buyback

Princeton, NJ; (August 9, 2005)—NRG Energy, Inc. (NYSE: NRG) today reported net income for the quarter ended June 30, 2005 of $23.9 million, or $0.22 per diluted share, including $0.7 million or $0.01 per diluted share related to discontinued operations. This compares with net income of $83.0 million, or $0.83 per diluted share, in the same period in 2004, which included $13.6 million or $0.14 per diluted share related to discontinued operations. For the six months ended June 30, 2005, NRG reported net income of $46.5 million, or $0.43 per diluted share including $0.7 million or $0.01 per diluted share related to discontinued operations. This compares with $113.3 million or $1.13 per diluted share in 2004, which included income of $12.4 million or $0.12 per diluted share related to discontinued operations.

Lower net income, primarily from West Coast Power (WCP), asset sales and reduced generation due to outages were partially offset by reduced interest expenses and a lower effective tax rate. The second quarter of 2004 included a $38.5 million pretax Connecticut Light & Power (CL&P) settlement gain. Mark-to-market charges associated with our hedging activity included a $5.1 million gain and a $33.1 million loss, respectively, for the three and six months ended June 30, 2005. The year-to-date results were also affected by approximately $60 million of mark-to-market gains related to forward electricity sales in the Northeast that were recorded at the end of 2004, approximately $51 million settled through June 30, 2005.

“While certain of our assets, such as our New York City plants, were called upon and performed at record levels, outages at several of our coal-fired units impacted our quarterly results,” commented David Crane, NRG President and Chief Executive Officer. “This quarter’s operating result illustrates the timeliness and importance of our business improvement program, F.O.R.NRG, announced last quarter.”

Accelerated Share Repurchase Program
NRG has committed to repurchase, on August 11, 2005, $250 million of the Company’s outstanding common stock from an affiliate of Credit Suisse First Boston LLC (CSFB). The Company will fund the planned repurchase with existing cash balances. To enable this share repurchase under the Company’s high yield debt indenture, the Company will issue simultaneously in a private transaction, $250 million of perpetual preferred stock. The cash proceeds from the preferred issuance will be used to repurchase approximately $229 million of our 8% high yield notes at 108% of par which will bring the total amount of our 8% notes redeemed during 2005 to $645 million.

“This accelerated share repurchase and the partial redemption of our 8% notes are both part of our continuing capital allocation program and underscore our commitment to the efficient deployment of capital,” said Crane. “While we expect over time to reinvest the lion’s share of our capital in enhancing our asset portfolio, NRG’s exceptional balance sheet strength and liquidity combined with

our projected free cash flow generation has caused us to conclude that, at this time, using a portion of our retained cash to repurchase our shares and bonds is a prudent and efficient use of capital.”

Second Quarter and Year-to-Date 2005 Highlights

	•		$122.6 million and $277.0 million of adjusted EBITDA for three and six months ending June 30, 2005, respectively, including $5.1 million of mark-to-market gain for the second quarter and a $33.1 million mark-to-market loss year-to-date (see Tables A-3 and A-4);

	•		$27.7 million and $91.5 million in cash flow from operations for the three and six months ending June 30, 2005, respectively;

	•		47% net debt-to-total capital at June 30, 2005 (see Table A-5);

	•		$1.35 billion in high-yield notes registered eliminating liquidated damages payments;

	•		90% increase in generation quarter over quarter from New York City assets; and

	•		$64.6 million in net proceeds from sale of Enfield completed on April 1, 2005.

Revenues were flat for three and six months ended June 30, 2005 versus last year because of higher merchant revenues attributed to the increased generation from our New York City assets and to a lesser extent from our NEPOOL assets during 2005. These were offset by lower capacity revenues due to the 2004 sale of Kendall, the absence of the Connecticut Light & Power $38.5 million pretax settlement recognized in second quarter 2004 and $33.1 million of year-to-date mark-to-market losses.

The cost of energy was 33% and 27% higher, respectively, for the three and six months ended June 30, 2005 versus 2004 levels primarily due to increased generation from our oil and gas-fired units. In addition, purchased power costs at our South Central operations increased to meet contract load obligations during its outages.

Operating and maintenance costs for three and six months ended June 30, 2005 increased over the comparable period in 2004 by $10.5 million and $20.0 million, respectively, due to an increase in major maintenance projects and more extensive outages in 2005 as compared to 2004. A portion of these incremental costs are the result of low-sulfur coal conversions of our eastern coal plants, which are a focus for much of the major maintenance and environmental capital expenditures in 2005.

Lower interest expense, higher other income, and lower income taxes partially offset the reduced operating income driven by the above described results. Interest expense for the three and six months ended June 30, 2005 was $50.6 million and $106.6 million, respectively, down from $66.2 and $129.0 million, respectively, for the comparable period in 2004 due to the sale of Kendall in the fourth quarter of 2004, the refinancing of our senior debt facility in December 2004, the $415.8 million redemption and purchases of our 8% notes during the first quarter, and the $57.2 million refinancing and prepayment of a portion of our Flinders project level debt in Australia during the six months ended June 30, 2005.

Regional Segment Review of Results

Table 1: Three Months Income from Continuing Operations before Taxes and Adjusted EBITDA by region


($in millions)	Income from Continuing						Adjusted EBITDA
	Operations before Taxes

Three months ending	6/30/05			6/30/04			6/30/05		6/30/04

Northeast	$	39.5		$	56.2		$	59.8	$	79.2
South Central	$	(6.8	)	$	16.5		$	8.4	$	31.9
Australia	$	5.4		$	(8.3	)	$	16.9	$	10.5
Western	$	5.9		$	23.2		$	6.1	$	54.9
Other North America	$	(5.6	)	$	(0.6	)	$	4.0	$	20.9
Other International	$	22.5		$	26.3		$	12.9	$	24.7
Alternative Energy, Non-generation, and Other	$	(29.7	)⁽¹⁾	$	(7.6	)⁽²⁾	$	14.5	$	10.8

Total	$	31.2		$	105.7		$	122.6	$	232.9


⁽¹⁾		Includes interest expense of $38.4 million and interest income.

⁽²⁾		Includes interest expense of $47.2 million, the $38.5 million CL&P settlement and interest income.

Table 2: Six Months Income from Continuing Operations before Taxes and Adjusted EBITDA by region


(in millions)	Income from Continuing						Adjusted EBITDA
	Operations before Taxes

Six months ending	6/30/05			6/30/04			6/30/05		6/30/04

Northeast	$	72.3		$	143.7		$	113.8	$	194.0
South Central	$	2.5		$	27.9		$	33.6	$	61.6
Australia	$	16.2		$	8.1		$	35.0	$	51.2
Western	$	9.2		$	24.6		$	9.6	$	88.2
Other North America	$	(10.5	)	$	(10.5	)	$	6.1	$	33.2
Other International	$	68.8		$	40.6		$	49.6	$	38.3
Alternative Energy, Non-generation, and Other	$	(99.9	)⁽¹⁾	$	(83.0	)⁽²⁾	$	29.3	$	23.6

Total	$	58.6		$	151.4		$	277.0	$	490.1


⁽¹⁾		Includes interest expense of $89.5 million and interest income.

⁽²⁾		Includes interest expense of $92.6 million, the $38.5 million CL&P settlement and interest income.

Northeast: Our New York City, and to a lesser extent, our NEPOOL assets were able to take advantage of higher average power prices, and improving spark and dark spreads, resulting from approximately 14% higher gas prices than in 2004. These spread improvements were offset by compressed margins from oil-fired plants and reduced generation output from our Huntley and Indian River assets due to increased outages versus 2004. Due to planned and unplanned outages, major maintenance expenses were higher by $8.6 and $14.6 million for the three and six months ended June 30, 2005, respectively, versus 2004. Finally, we recorded a mark-to-market gain of $5.1

million and $33.1 million loss for the three and six months ended June 30, 2005, respectively, related to forward sales not receiving hedge accounting treatment.

South Central: Total generation from the South Central assets decreased by 18% and 5%, respectively, for three and six months ended June 30, 2005, due to both planned and unplanned outages. To meet contract load requirements, the South Central region had to purchase energy at prices higher than its generation costs. A planned outage during the first half of 2005 also contributed to $7.9 million of higher major maintenance costs versus the same period last year.

Australia: Income from continuing operations before taxes results improved for the three and six months ended June 30, 2005, driven by increased generation at Flinders due to the start of full commercial operation of the Playford station during the first quarter 2005 and a planned outage that occurred in the second quarter of 2004. Adjusted EBITDA for the three months was up versus the prior year due to higher generation and stronger exchange rates and pool prices. However, an extremely mild summer significantly depressed pool prices during the first quarter 2005, affecting overall six month results.

Western, Other North America, International and Other: In the aggregate, income from continuing operations before taxes and adjusted EBITDA results decreased for the quarter and six months ended June 30, 2005 from 2004 primarily due to a series of portfolio changes:

	•		The expiration of the CDWR contract at the end of 2004 lowered the Western region results;

	•		The sale of the Kendall project in the fourth quarter of 2004 reduced the Other North American results in 2005; and

	•		International and Other results were impacted by the April 2005 Enfield sale, the collection of the TermoRio note in the first quarter 2005, and the $38.5 million pre-tax CL&P settlement gain in 2004.

Liquidity and Capital Resources
Liquidity remained strong at $1.2 billion, as of June 30, 2005, even after the Company paid down $473.0 million in debt during the first and second quarter. This cash outflow was partially offset by the first quarter 2005 collection of the $71 million TermoRio arbitration award, an April 2005 $50 million dividend distribution from WCP, the $64.6 million in Enfield sale proceeds and cash from operations.

Table 3: Corporate Liquidity


(in millions)	June 30, 2005		December 31, 2004

Unrestricted Cash:
Domestic	$	493	$	921
International		330		189
Restricted Cash:
Domestic		66		54
International		21		59

Total Cash	$	910	$	1,223
Letter of Credit Availability		172		193
Revolver Availability		150		150

Total Current Liquidity	$	1,232	$	1,566

Capital Allocation
The Company continuously monitors its capital structure, liquidity, and cash flow and has been assessing for several months how to optimize the utilization of its current cash resources. The planned capital transaction is designed to provide a cost effective return of capital to shareholders, with certainty of execution, while preserving the Company’s flexibility for future capital allocation decisions. Upon completion of this transaction, the Company’s net debt to total capital remains at approximately 47%, the lower end of our targeted range.

On August 8, the Company executed a commitment to sell to CSFB, in a private placement, $250 million in new 3.625% perpetual preferred stock. The preferred stock may be settled at the option of CSFB or the Company during a 90 day period commencing August 11, 2015. Upon settlement, NRG will pay CSFB $250 million in cash to redeem the preferred stock. If the market value of the underlying NRG common shares is in excess of 150% of the August 10, 2005 issuance price, NRG will pay CSFB the net difference in cash or shares at settlement. If the Company’s common share price is lower at settlement than the issuance price, CSFB will pay NRG the net difference in cash or shares. Only common shares equal to the value of the security in excess of 150% of the issuance price will be included in the earnings per share dilution calculation.

Issuing the preferred stock also gives NRG the capacity under our debt instruments to use existing cash to fund the accelerated share repurchase program announced today. Under the terms of the accelerated share repurchase agreement with CSFB, NRG will have fixed its price risk under the program at 97%-103% of the common share price at execution. NRG’s outstanding shares will decrease by the full amount repurchased on August 11, 2005 based on NRG’s August 10, 2005 closing price.

Focus on Return on Invested Capital at NRG (F.O.R.NRG)
During the first quarter earnings call, NRG announced F.O.R.NRG, a comprehensive cost and margin improvement program consisting of a large number of asset, portfolio and headquarters-specific initiatives being implemented over the short-to-medium term. Our improvement plan will contribute $100 million annually by the end of 2008, and $30 million in benefits are expected in 2005. Approximately $18 million of benefits were achieved during the second quarter.

We currently have approximately 85 projects that are either scheduled for implementation or are under technical and financial evaluation. Currently we have over 20 projects in active implementation as part of F.O.R.NRG.

Outlook
In the third quarter, as it has progressed to date, the Company has benefited from a strong energy price environment created by favorable weather conditions across our Northeast region. While our baseload coal plants were substantially contracted going into the quarter, our entire fleet of plants have performed well during the hot weather periods enabling us to derive incremental benefit from the strong spot pricing environment. As the recent weather-driven pricing environment contains significant risks as well as significant opportunity for our heavily-contracted portfolio, we are not modifying our previous 2005 adjusted EBITDA guidance of $600 million. Net cash provided by operating activities is expected to be $419 million and reflects increased collateral requirements.

The Company’s adjusted EBITDA guidance of $600 million (see Table A-10) includes approximately $33.1 million of mark-to-market losses through June 30, 2005, which have been substantially offset by the F.O.R.NRG corporate initiatives.

This guidance excludes unusual or nonrecurring events and assumes normal weather patterns in our core regions for the balance of the year. The gross margin associated with this EBITDA estimate is substantially hedged in terms of downside protection while the Company retains the potential to benefit from extreme weather events, locational supply-demand imbalances, and gas price spikes through its dual fuel-fired peaking units.

Earnings Conference Call
On August 9, 2005, NRG will host a conference call at 9:00 a.m. eastern to discuss these results. To access the live webcast and accompanying slide presentation, log on to NRG’s website at http://www.nrgenergy.com and click on “Investors.” To participate in the call, dial 877.407.8035. International callers should dial 201.689.8035. Participants should dial in or log on approximately five minutes prior to the scheduled start time.

The call will be available for replay shortly after completion of the live event on the “Investors” section of the NRG website.

About NRG
NRG Energy, Inc. owns and operates a diverse portfolio of power-generating facilities, primarily in the Northeast, South Central and West Coast regions of the United States. Its operations include baseload, intermediate, peaking, and cogeneration facilities, thermal energy production and energy resource recovery facilities. NRG also has ownership interests in international generating facilities in Australia and Germany.

Safe Harbor Disclosure

This news release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Such forward-looking statements are subject to certain risks, uncertainties and assumptions and include, but are not limited to, expected earnings, future growth and financial performance, expected benefits and results of capital allocation initiatives, expected benefits and EBITDA improvements of the F.O.R. NRG initiative and typically can be identified by the use of words such as “will,” “expect,” “estimate,” “anticipate,” “forecast,” “plan,” “believe” and similar terms. Although NRG believes that its expectations are reasonable, it can give no assurance that these expectations will prove to have been correct, and actual results may vary materially. Factors that could cause actual results to differ materially from those contemplated above include, among others, general economic conditions, hazards customary in the power industry, weather conditions, competition in wholesale power markets, the volatility of energy and fuel prices, failure of customers to perform under contracts, changes in the wholesale power markets and related government regulation, the condition of capital markets generally, our ability to access capital markets, unanticipated outages at our generation facilities, our ability to convert facilities to use western coal successfully, adverse results in current and future litigation, the inability to implement value enhancing improvements to plant operations and company-wide processes and the ability to complete the accelerated share repurchase program and preferred stock issuance.

NRG undertakes no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. The adjusted EBITDA guidance is an estimate as of today’s date, August 9, 2005 and is based on assumptions believed to be reasonable as of this date. NRG expressly disclaims any current intention to update such guidance. The foregoing review of factors that could cause NRG’s actual

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

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

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

NRG ENERGY, INC. AND SUBSIDIARIES
Reconciliation of NonGAAP Financial Measures

Appendix Table A-1: Adjusted Net Income Reconciliation

The following table summarizes the calculation of adjusted net income and provides a reconciliation to GAAP net income/(loss), including per share amounts.


	Three Months Ended					Three Months Ended
									Diluted
(Dollars in thousands, except per share amounts)	06/30/2005			Diluted EPS		06/30/2004			EPS

Net Income	$	23,866		$	0.22	$	83,024		$	0.83
Plus:
Income from Discontinued Operations, net of tax		(734	)		—		(13,624	)		(0.14	)
Corporate relocation charges, net of tax		276			—		3,412			0.03
Reorganization items, net of tax		—			—		(1,609	)		(0.02	)
Impairment charge, net of tax		135			—		1,013			0.01
FERC-authorized settlement with CL&P, net of tax		—			—		(23,279	)		(0.23	)
Write downs and (gains)/losses on sales of equity method investments, net of tax		(192	)		—		(728	)		(0.01	)

Adjusted Net Income	$	23,351		$	0.22	$	48,209		$	0.48

Appendix Table A-2: Adjusted Net Income Reconciliation

The following table summarizes the calculation of adjusted net income and provides a reconciliation to GAAP net income/(loss), including per share amounts.


	Six Months Ended						Six Months Ended
										Diluted
(Dollars in thousands, except per share amounts)	06/30/2005			Diluted EPS			06/30/2004			EPS

Net Income	$	46,484		$	0.43		$	113,259		$	1.13
Plus:
Income from Discontinued Operations, net of tax		(730	)		(0.01	)		(12,413	)		(0.12	)
Corporate relocation charges, net of tax		2,364			0.03			4,087			0.04
Reorganization items, net of tax		—			—			2,170			0.02
Impairment charges, net of tax		135			—			1,013			0.01
FERC-authorized settlement with CL&P, net of tax		—			—			(23,279	)		(0.23	)
Proceeds received on Crockett contingency		(2,138	)		(0.02	)		—			—
Gain on TermoRio settlement		(8,180	)		(0.09	)		—			—
Write downs and (gains)/losses on sales of equity method investments, net of tax		(192	)		—			322			0.00

Adjusted Net Income	$	37,743		$	0.33		$	85,159		$	0.85

Appendix Table A-3: Three Month EBITDA Reconciliation

The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss):


	Three Months Ended		Three Months Ended
	06/30/2005		06/30/2004
Net Income:	$	23,866	$	83,024
Plus:
Income Tax Expense		8,081		36,322
Interest Expense		47,946		60,209
Amortization and Write Downs of Finance Costs		1,435		2,474


	Three Months Ended			Three Months Ended
	06/30/2005			06/30/2004
Amortization of Debt Discount/Premium		1,179			3,542
Depreciation Expense		47,749			53,168
WCP CDWR contract amortization		—			30,638
Amortization of power contracts		1,294			8,614
Amortization of emission credits		2,690			3,648

EBITDA		134,240			281,638
Income from Discontinued Operations		(734	)		(13,624	)
Corporate relocation charges		456			5,645
Reorganization items		—			(2,661	)
Impairment charges		223			1,676
FERC-authorized settlement with CL&P		—			(38,509	)
Write Downs, (Gain)/Loss on Sales of Equity Investments		(11,561	)		(1,205	)

Adjusted EBITDA	$	122,624		$	232,961

Appendix Table A-4: Six Month EBITDA Reconciliation

The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss):


	Six Months Ended			Six Months Ended
	06/30/2005			06/30/2004
Net Income:	$	46,484		$	113,259
Plus:
Income Tax Expense		12,883			50,602
Interest Expense		101,593			117,094
Amortization and Write Downs of Finance Costs		2,848			4,537
Amortization of Debt Discount/Premium		2,110			7,323
Refinancing Expenses		25,024			30,417
Depreciation Expense		96,173			108,174
WCP CDWR contract amortization		—			61,606
Amortization of power contracts		8,822			25,579
Amortization of emission credits		6,316			9,918

EBITDA		302,253			528,509
Income from Discontinued Operations		(730	)		(12,413	)
Corporate relocation charges		3,911			6,761
Reorganization items		—			3,589
Impairment charges		223			1,676
FERC-authorized settlement with CL&P		—			(38,509	)
Gain on Crockeet		(3,536	)		—
Gain on TermoRio Settlement		(13,532	)		—
Write Downs, Gain/(Loss) on Sales of Equity Investments		(11,561	)		533

Adjusted EBITDA	$	277,028		$	490,145

Appendix Table A-5: Net Debt to Capital Reconciliation

The following table summarizes the calculation of Net Debt to Capital:


Numerator	Gross Debt	3,210,951
	Total Cash	910,409

	Net Debt	2,300,542

Denominator	Book Value of Equity	2,600,651
	Net Debt	2,300,542

	Capital	4,901,193
Net Debt to Capital		47	%

Appendix Table A-6: Second Quarter 2005 Regional EBITDA Reconciliation

The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss):


			South						Other					Other			Alt.
Three months ending June 30, 2005	Northeast		Central			Western			NA			Australia		Int'l			Energy		Non-Gen			Corp

Net Income:		39,473		(6,817	)		5,909			(5,967	)		4,213		18,438			3,120		1,834			(36,337	)
Plus:
Income Tax Expense/(Benefit)		—		—			(3	)		1,126			1,142		4,068			174		537			1,037
Interest Expense		9		1,742			—			4,414			3,056		1,128			95		2,262			35,242
Amortization and Write Downs of Finance Costs		—		—			—			—			22		—			—		5			1,408
Amortization of Debt (Discount)/Premium		—		602			—			1,221			—		—			—		(232	)		(412	)
Depreciation Expense		18,582		15,085			197			2,010			6,118		858			1,318		2,740			841
Amortization of power contract		—		(3,162	)		—			1,888			2,354		—			—		214			—
Amortization of emission credits		1,744		945			—			—			—		—			—		—			—
EBITDA		59,808		8,395			6,103			4,692			16,905		24,492			4,707		7,360			1,779
Income from discontinued operations		—		—			—			(734	)		—		—			—		—			—
Corporate relocation charges		8		2			—			—			—		—			—		—			446
Impairment charges		—		—			—			—			—		—			223		—			—
Write down and (gains)/losses on sales of equity method investments		—		—			—			—			—		(11,561	)		—		—			—
Adjusted EBITDA	$	59,816	$	8,397			6,103		$	3,958		$	16,905	$	12,931		$	4,930	$	7,360		$	2,225

Appendix Table A-7: Second Quarter 2004 Regional EBITDA Reconciliation

The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss):


			South					Other						Other			Alt.
Three months ending June 30, 2004	Northeast		Central			Western		NA			Australia			Int'l			Energy			Non-Gen			Corp

Net Income:		56,230		16,494			23,052		938			(4,908	)		33,194			3,731			43,703			(89,410	)
Plus:
Income Tax Expense/(Benefit)		—		—			185		409			(3,370	)		5,307			4			448			33,339
Interest Expense		1,392		664			3		8,617			6,138			(2,156	)		9			2,410			43,133
Amortization and Write Downs of Finance Costs		—		—			—		—			—			—			—			—			2,474
Amortization of Debt Discount/Premium		—		631			—		3,942			(175	)		—			(3	)		(271	)		(582	)
Refinancing Expenses		—		—			—		—			—			—			—			—			—
Depreciation Expense		17,382		14,572			203		6,930			6,885			613			1,289			2,729			2,565
WCP CDWR contract amortization		—		—			30,638		—			—			—			—			—			—
Amortization of power contract		1,889		(3,465	)		830		2,500			6,646			—			—			214			—
Amortization of emission credits		2,276		1,373			—		—			—			—			—			—			—
EBITDA		79,169		30,269			54,911		23,336			11,216			36,958			5,030			49,233			(8,481	)
Income from discontinued operations		—		—			—		(1,917	)		—			(12,237	)		530			—			(3)
Corporate relocation charges		—		1			—		—			—			—			—			—			5,644
Reorganization items		28		(71	)		—		—			—			(1	)		—			(528	)		(2,090	)
Impairment charges		—		1,676			—		1			—			—			—			—			—
FERC-authorized settlement with CL&P		—		—			—		—			—			—			—			(38,509	)		—
Write Downs and (gain)/Loss on Sales of Equity		—		—			—		(500	)		(705	)		—			—			—			—
Investments
Adjusted EBITDA	$	79,197	$	31,875		$	54,911	$	20,920		$	10,511		$	24,720		$	5,560		$	10,140		$	(4,930	)

Appendix Table A-8: Six Months 2005 Regional EBITDA Reconciliation

The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss):


			South					Other						Other			Alt.
Six months ending June 30, 2005	Northeast		Central			Western		NA			Australia			Int'l			Energy		Non-Gen			Corp

Net Income:		72,333		2,489			9,168		(11,129	)		14,393			60,706			3,658		6,943			(112,077	)
Plus:
Income Tax Expense		—		—			25		1,348			1,776			8,137			416		552			629
Interest Expense		97		3,484			—		8,832			6,675			4,232			121		4,505			73,649
Amortization and Write Downs of Finance Costs		—		—			—		—			28			—			—		10			2,810
Amortization of Debt Discount/Premium		—		1,200			—		2,454			(193	)		—			—		(466	)		(885	)
Refinancing Expense		—		—			—		—			(9,783	)		—			—		—			34,806
Depreciation Expense		37,191		30,227			395		4,003			12,712			1,654			2,634		5,479			1,878
Amortization of power contract		—		(5,898	)		—		4,862			9,430			—			—		428			—
Amortization of emission credits		4,212		2,103			—		—			—			—			—		—			—
EBITDA		113,833		33,605			9,588		10,370			35,038			74,729			6,829		17,451			810
Income from discontinued operations		—		—			—		(730	)		—			—			—		—			—
Corporate relocation charges		12		2			—		—			—			—			—		—			3,897
Impairment charges		—		—			—		—			—			—			223		—			—
Gain on TermoRio		—		—			—		—			—			(13,532	)		—		—			—
Gain on Crockett		—		—			—		(3,536	)		—			—			—		—			—
Write down and (gains)/losses on sales of equity method investments		—		—			—		—			—			(11,561	)		—		—			—
Adjusted EBITDA	$	113,845	$	33,607		$	9,588	$	6,104		$	35,038		$	49,636		$	7,052	$	17,451		$	4,707

Appendix Table A-9: Six Months 2004 Regional EBITDA Reconciliation

The following table summarizes the calculation of EBITDA and provides a reconciliation to net income/(loss):


			South					Other						Other			Alt.
Six months ending June 30, 2004	Northeast		Central			Western		NA			Australia			Int'l			Energy			Non-Gen			Corp

Net Income:		143,658		27,871			24,263		(10,281	)		8,228			43,524			4,275			52,437			(180,716	)
Plus:
Income Tax Expense/(Benefit)		—		—			337		744			(106	)		9,450			8			626			39,543
Interest Expense		678		2,380			3		16,838			11,306			(3,659	)		16			4,916			84,616
Amortization and Write Downs of Finance Costs		—		—			—		—			—			—			—			—			4,537
Amortization of Debt (Discount)/Premium		—		1,265			—		7,908			(361	)		—			(8	)		(555	)		(926	)
Refinancing expense		—		—			—		—			—			—			—			—			30,417
Depreciation Expense		35,911		31,534			405		14,540			12,011			1,337			2,678			5,853			3,905
WCP CDWR contract amortization		—		—			61,606		—			—			—			—			—			-
Amortization of power contract		6,375		(6,660	)		1,644		4,983			18,809			—			—			428			-
Amortization of emission credits		7,027		2,891			—		—			—			—			—			—			-
EBITDA		193,649		59,281			88,258		34,732			49,887			50,652			6,969			63,705			(18,624	)
(Income)/ Loss from discontinued operations		—		—			—		(933	)		—			(12,357	)		877			—			-
Corporate Relocation Charges		—		1			—		—			—			—			—			—			6,760
Reorganization Items		349		653			—		151			—			—			—			160			2,276
Impairment charges		—		1,676			—		—			—			—			—			—			-
FERC-authorized settlement with CL&P		—		—			—		—			—			—			—			(38,509	)		-
Write Downs, Gain/(Loss) on Sales of Equity Investments		—		—			—		(735	)		1,268			—			—			—			-
Adjusted EBITDA	$	193,998	$	61,611		$	88,258	$	33,215		$	51,155		$	38,295		$	7,846		$	25,300		$	(9,588	)

Appendix Table A-10: Forecasted EBITDA Reconciliation

The following table summarizes the calculation of adjusted EBITDA and provides a reconciliation to forecasted cash flow from operations:


$ in millions	Outlook
EBITDA	$	632
Nonrecurring Items		(32	)

Adjusted EBITDA		600
Interest Payments		(225	)
Income Tax		(13	)
Other Cash Used by Operations		104
Working Capital Changes		(47	)

Cash Flow from Operations	$	419

EBITDA, Adjusted EBITDA and adjusted net income are nonGAAP financial measures. These measurements are not recognized in accordance with GAAP and should not be viewed as an alternative to GAAP measures of performance. The presentation of Adjusted EBITDA and adjusted net income should not be construed as an inference that NRG’s future results will be unaffected by unusual or non-recurring items.

EBITDA represents net income before interest, taxes, depreciation and amortization. EBITDA is presented because NRG considers it an important supplemental measure of its performance and believes debt-holders frequently use EBITDA to analyze operating

performance and debt service capacity. EBITDA has limitations as an analytical tool, and you should not consider it in isolation, or as a substitute for analysis of our operating results as reported under GAAP. Some of these limitations are:

	•		EBITDA does not reflect cash expenditures, or future requirements for capital expenditures, or contractual commitments;

	•		EBITDA does not reflect changes in, or cash requirements for, working capital needs;

	•		EBITDA does not reflect the significant interest expense, or the cash requirements necessary to service interest or principal payments, on debts;

	•		Although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA does not reflect any cash requirements for such replacements; and

	•		Other companies in this industry may calculate EBITDA differently than NRG does, limiting its usefulness as a comparative measure.

Because of these limitations, EBITDA should not be considered as a measure of discretionary cash available to use to invest in the growth of NRG’s business. NRG compensates for these limitations by relying primarily on our GAAP results and using EBITDA and Adjusted EBITDA only supplementally. See the statements of cash flow included in the financial statements that are a part of this news release.

Adjusted EBITDA is presented as a further supplemental measure of operating performance. Adjusted EBITDA represents EBITDA adjusted for reorganization, restructuring, impairment and corporate relocation charges, discontinued operations, and write downs and gains or losses on the sales of equity method investments; factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. As an analytical tool, Adjusted EBITDA is subject to all of the limitations applicable to EBITDA. In addition, in evaluating Adjusted EBITDA, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.

Similar to Adjusted EBITDA, Adjusted net income represents net income adjusted for reorganization, restructuring, impairment and corporate relocation charges, discontinued operations, and write downs and gains or losses on the sales of equity method investments; factors which we do not consider indicative of future operating performance. The reader is encouraged to evaluate each adjustment and the reasons NRG considers it appropriate for supplemental analysis. In addition, in evaluating adjusted net income, the reader should be aware that in the future NRG may incur expenses similar to the adjustments in this news release.


		Meredith Moore		Nahla Azmy
		Media Relations		Investor Relations
		609.524.4522		609.524.4526

		Jay Mandel		Katy Sullivan
		Media Relations		Investor Relations
		609.524.4525		609.524.4527